UNITED STATES
Form 10-Q
Devon Energy Corporation
Registrant’s telephone number, including area code:
Former name, former address and former fiscal year, if changed from last report.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o
The number of shares outstanding of Registrant’s common stock, par value $.10, as of April 30, 2003, was 230,784,995.
TABLE OF CONTENTS
DEVON ENERGY CORPORATION
DEFINITIONS
As used in this document:
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PART I. FINANCIAL INFORMATION
(Forming a part of Form 10-Q Quarterly Report
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DEVON ENERGY CORPORATION AND SUBSIDIARIES
See accompanying notes to consolidated financial statements.
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The accompanying consolidated financial statements and notes thereto have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the consolidated financial statements and notes thereto included in Devon’s 2002 Annual Report on Form 10-K.
In the opinion of Devon’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the consolidated financial position of Devon and its subsidiaries as of March 31, 2003, and the results of their operations and their cash flows for the three month periods ended March 31, 2003 and 2002.
On April 25, 2003, Devon completed its merger with Ocean Energy Inc. (“Ocean”). In the transaction, Devon issued 0.414 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 74 million shares). Also, Devon assumed approximately $1.8 billion of debt from Ocean.
Devon acquired Ocean for the significant development projects and exploration prospects in both the deepwater Gulf of Mexico and internationally and expanded exposure to both the Gulf of Mexico and international markets.
The calculation of the purchase price and the preliminary allocation to assets and liabilities as of April 25, 2003, are shown below. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and fair value of the assets and liabilities as of the acquisition date have not been completed.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Set forth in the following table is certain unaudited pro forma financial information as of March 31, 2003, and for the three-month periods ended March 31, 2003 and 2002. The information as of March 31, 2003, assumes the Ocean merger had closed on such date. The information for the three-month periods ended March 31, 2003 and 2002, has been prepared assuming the Ocean merger and the Mitchell merger were consummated on January 1, 2002. All pro forma information is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transactions had occurred in the past, Devon’s operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Devon would have achieved if the transactions had occurred on January 1, 2002.
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The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions.
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Devon has periodically entered into oil and gas financial instruments and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on certain Canadian gas revenues that are based on U.S. dollar prices. The hedging instruments are usually placed with counterparties that Devon believes are minimal credit risks. It is Devon’s policy to only enter into derivative contracts with investment grade rated counterparties deemed by management to be competent and competitive market makers. The oil and
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gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
As of March 31, 2003, $187 million of net deferred losses on derivative instruments in “accumulated other comprehensive loss” are expected to be reclassified to earnings from operations during the next 12 months. Transactions and events expected to occur over the next 12 months that will necessitate reclassifying these derivatives’ losses to earnings from operations are primarily the production and sale of the hedged oil and gas quantities. The maximum term over which Devon is hedging exposures to the variability of cash flows for commodity price risk is 21 months.
Devon recorded in its statements of operations a gain of $10 million and a loss of $17 million in the first quarter of 2003 and 2002, respectively, for the change in fair value of derivative instruments that do not qualify for hedge accounting treatment, as well as the ineffectiveness of derivatives that do qualify as hedges. Included in the three-month periods ended March 31, 2003 and 2002 are net gains of $1 million and $7 million, respectively, related to such ineffectiveness. These gains are related to both (i) the ineffectiveness of the various cash flow hedges and (ii) the component of the derivative instrument gain or loss excluded from the assessment of hedge effectiveness.
Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations(SFAS No. 143) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation. SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants. The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation for settlement. The initial measurement of the asset retirement obligation is fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.”
The asset retirement cost equal to the fair value of the retirement obligation is capitalized as part of the cost of the related long-lived asset and allocated to expense using a systematic and rational method.
Devon previously estimated costs of dismantlement, removal, site reclamation, and other similar activities in the total costs that are subject to depreciation, depletion, and amortization. However, Devon did not record a separate asset or liability for such amounts. Upon adoption, Devon recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million. Additionally, Devon established an asset retirement obligation of $453 million, an increase to property and equipment of $400 million and a decrease in accumulated DD&A of $79 million.
Following is a reconciliation of the asset retirement obligation from December 31, 2002 to March 31, 2003.
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Following is a reconciliation of reported net income and the related earnings per share amounts assuming the provisions of SFAS No. 143 had been adopted as of January 1, 2000.
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Following is a summary of the asset retirement obligation assuming the provisions of SFAS No. 143 had been adopted as of January 1, 2000.
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The following tables reconcile the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for the three-month periods ended March 31, 2003 and 2002.
The senior convertible debentures were not included in the 2002 dilution calculation because the inclusion was anti-dilutive.
Certain options to purchase shares of Devon’s common stock have been excluded from the dilution calculations because the options’ exercise price exceeded the average market price of Devon’s common stock during the applicable period. The following information relates to these options.
The excluded options for 2003 expire between April 30, 2003 and December 2, 2012.
Devon applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees,and related interpretations, in accounting for its fixed plan stock options. As such, compensation expense would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123.
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Had Devon elected the fair value provisions of SFAS No. 123 and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, Devon’s first quarter 2003 and 2002 pro forma net earnings and pro forma net earnings per share would have differed from the amounts actually reported as shown in the following table.
Cash payments (refunds) for interest and income taxes in the first quarter of 2003 and 2002 are presented below:
The first quarter 2002 Mitchell acquisition involved non-cash consideration as presented below:
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Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three reportable segments: its operations in the U.S., its operations in Canada and its international operations outside of North America. Substantially all of these segments’ operations involve oil and gas producing activities. Following is certain financial information regarding Devon’s segments for the first quarters of 2003 and 2002. The revenues reported are all from external customers.
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Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals although actual amounts could differ from management’s estimate.
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon’s consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of March 31, 2003, Devon’s consolidated balance sheet included $7 million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.
Numerous gas producers and related parties, including Devon, have been named in various lawsuits filed by private litigants alleging violation of the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions, improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The various suits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suits, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with these lawsuits and no liability has been recorded in connection therewith.
Also, pending in federal court in Texas is a similar suit alleging underpaid royalties to the United States in connection with natural gas and natural gas liquids produced and sold from United States owned
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and/or controlled lands. The claims were filed by private litigants against Devon and numerous other producers, under the federal False Claims Act. The United States served notice of its intent to intervene as to certain defendants, but not Devon. Devon and certain other defendants are challenging the constitutionality of whether a claim under the federal False Claims Act can be maintained absent government intervention. Devon believes that it has acted reasonably and paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this litigation. As a result, Devon’s monetary exposure in this suit is not expected to be material.
Devon is a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post production costs from royalties payable by Devon. The plaintiffs in these lawsuits propose to expand them into county or state-wide class actions relating specifically to transportation and related costs associated with Devon’s Wyoming gas production. A significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of which Devon owns a 75% interest. Devon believes that it has acted reasonably and paid royalties in good faith and in accordance with its obligations under its oil and gas leases and applicable law, and Devon does not believe that it is subject to material exposure in association with this litigation.
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
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The following discussion addresses material changes in results of operations for the three months ended March 31, 2003, compared to the three months ended March 31, 2002, and in financial condition since December 31, 2002. It is presumed that readers have read or have access to Devon’s 2002 Annual Report on Form 10-K which includes disclosures regarding critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
Net earnings for the first quarter of 2003 were $436 million, or $2.76 per share. This compares to net earnings of $62 million, or $0.41 per share for the first quarter of 2002. The increase in first quarter earnings was due to an increase in oil, natural gas and NGL prices, the effects of which were partially offset by a decrease in production primarily due to the 2002 property divestitures and increased expenses.
On February 24, 2003, Devon and Ocean Energy Inc. (“Ocean”) announced their intention to merge. This merger was completed on April 25, 2003. In the transaction, Devon issued 0.414 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 74 million shares). Also, Devon assumed approximately $1.8 billion of debt from Ocean. This merger had no effect on Devon’s financial condition or results of operations during the first quarter of 2003.
Results of Operations
Total revenues increased $768 million, or 85%, in the first quarter of 2003. This was the result of increases in the average prices of oil, gas and NGLs and an increase in marketing and midstream revenue, partially offset by lower production on a combined Boe basis. Oil, gas and NGL revenues increased $494 million, or 66%, for the first quarter of 2003 compared to the first quarter of 2002. The quarterly comparisons of production and price changes are shown in the following tables. (Note: Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)
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In addition to the volumes included in the prior tables for domestic and Canadian production, in the first quarter of 2003 and 2002, Devon also produced 286,000 and 481,000 barrels of oil, respectively, in its International division. The oil revenues generated by this production were $9 million and $10 million, respectively.
The average sales prices per unit of production shown in the preceding tables include the effect of Devon’s hedging activities. Following is a comparison of Devon’s average sales prices with and without the effect of hedges for the three-month periods ended March 31, 2003 and 2002.
Oil Revenues. Oil revenues increased $34 million in the first quarter of 2003. Oil revenues increased $86 million due to a $9.47 per barrel increase in the average price of oil. This was partially offset by a decrease in production of 3 million barrels which caused oil revenues to decrease $52 million. The production decline was primarily the result of divestitures that occurred throughout 2002.
Gas Revenues. Gas revenues increased $408 million in 2003’s first quarter. A $2.43 per Mcf increase in the average gas price in first quarter 2003 caused gas revenues to increase $438 million. This was partially offset by a decrease in production of 12 Bcf which caused gas revenues to decrease $30 million. The production decline was primarily the result of divestitures that occurred throughout 2002.
NGL Revenues. NGL revenues increased $52 million in the first quarter of 2003. Of this total increase, $45 million was due to an $8.93 per barrel increase in the average NGL price in the first quarter of 2003. A one million barrel increase in 2003 production accounted for the remainder of the increase in NGL revenues. Production from new drilling and development was partially offset by the effect of divestitures that occurred throughout 2002.
Marketing and Midstream Revenues.Marketing and midstream revenues increased $274 million, or 171%, in the first quarter of 2003. Of this total increase, $111 million was the result of an increase in gas and NGL prices. An increase in third-party processed NGL volumes resulted in the remaining increase in first quarter 2003 revenues. The increase in volumes was primarily related to new drilling and development in the Barnett Shale and an additional 24 days of production in 2003 due to the timing of the January 2002 Mitchell merger.
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Production and Operating Expenses.The components of production and operating expenses for the first quarter of 2003 and 2002 are set forth in the following tables.
Lease operating expenses increased $11 million in the first quarter of 2003. The increase was primarily related to an increase in well workover expenses and increased power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $4 million increase in costs. These increases were partially offset by property divestitures that occurred throughout 2002.
Transportation costs increased $3 million, primarily due to an increase in gas production in higher costs areas.
Production taxes increased $25 million in the 2003 quarter. The majority of Devon’s production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 70% increase in domestic oil, gas and NGL revenues in the first quarter of 2003 was the primary cause of the production tax increase.
Marketing and Midstream Costs and Expenses.Marketing and midstream costs and expenses increased $231 million, or 185%, in the first quarter of 2003. Of this total increase, $81 million was the result of an increase in gas and NGL prices. An increase in third-party processed NGL volumes resulted in the remaining increase in first quarter 2003 costs and expenses. The increase in volumes was primarily related to new drilling and development in the Barnett Shale and an additional 24 days of production in 2003 due to the timing of the January 2002 Mitchell merger.
Depreciation, Depletion and Amortization Expenses (“DD&A”). Oil and gas property related DD&A decreased $21 million, or 7%, from $289 million in the first quarter of 2002 to $268 million in the first quarter of 2003. Oil and gas property related DD&A expense decreased $26 million due to the 8% decrease in combined oil, gas and NGLs production in 2003. This was partially offset by an increase in the combined U.S., Canadian and international DD&A rate from $5.95 per Boe in 2002 to $6.05 per Boe in 2003 which caused oil and gas property related DD&A to increase by $5 million. The adoption of SFAS No. 143 had an immaterial effect on first quarter 2003 DD&A expense.
Non-oil and gas property DD&A expense increased $6 million from $22 million in the first quarter of 2002 compared to $28 million in the first quarter of 2003. Depreciation for an additional 24 days in 2003 versus 2002 for the marketing and midstream assets acquired in the January 2002 Mitchell acquisition accounted for most of the increase.
Accretion of Asset Retirement Liability.Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations(SFAS No. 143)
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As required by SFAS No. 143, Devon recorded $7 million of accretion expense during the first quarter of 2003.
General and Administrative Expenses (“G&A”). Devon’s net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full-cost method of accounting. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. The following table is a summary of G&A expenses by component for the first quarter of 2003 and 2002.
Net G&A decreased $1 million in the first quarter of 2003 compared to the first quarter of 2002. Gross G&A decreased $7 million. The decrease in gross expenses in the first quarter of 2003 was primarily related to lower employee salaries as a result of lower headcount and from lower professional fees.
G&A increased $3 million due to a decrease in the amount capitalized as part of oil and gas properties. G&A also increased $3 million due to a decrease in the amount of reimbursements on operated properties in the 2003 quarter. The change in capitalized G&A was primarily related to the lower personnel related expenses and other costs subject to capitalization. The change in reimbursed G&A was primarily related to property divestitures.
Interest Expense.Interest expense increased $6 million in 2003’s first quarter. An increase in the average interest rate on outstanding debt from 5.7% in the 2002 quarter to 6.3% in the 2003 quarter caused interest expense to increase by $10 million. The increase in the average interest rate was due primarily to the March 2002 issuance of $1 billion of bonds at 7.95%. These bonds were used primarily to pay down on the $3 billion term loan credit facility which had an average interest rate of less than 3%. This was partially offset by a decrease in the average debt balance outstanding from $8.3 billion in 2002 to $8.0 billion in 2003 which caused interest expense to decrease by $5 million. The decrease in the average debt balance in the first quarter of 2003 was primarily attributable to the utilization of proceeds from the 2002 property divestitures to retire outstanding debt.
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Other items included in interest expense that are not related to the debt balance outstanding were $1 million higher in the 2003 quarter compared to the 2002 quarter. These items include facility and agency fees, amortization of costs and other miscellaneous items.
Effects of Changes in Foreign Currency Exchange Rates. Devon’s Canadian subsidiary has certain fixed-rate senior notes which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar from the dates the notes were acquired to the dates of repayment increase or decrease the expected amount of Canadian dollars eventually required to repay the notes. In addition, Devon’s Canadian subsidiary has cash and other working capital amounts denominated in U.S. dollars which also fluctuate in value with changes in the exchange rate. Such changes in the Canadian dollar equivalent balance of the debt and working capital balances are required to be included in determining net earnings for the period in which the exchange rate changes. The increase in the Canadian-to-U.S. dollar exchange rate from $0.6331 at December 31, 2002 to $0.6806 at March 31, 2003 resulted in a $22 million gain.
Income Taxes. During interim periods, income tax expense is based on the estimated effective income tax rate that is expected for the entire fiscal year. The estimated effective tax rate in the first quarter of 2003 was 32%, compared to 23% estimated in the first quarter of 2002.
The 2003 and 2002 rates were lower than the statutory federal tax rate primarily due to the tax benefits of certain foreign deductions. The 2003 rate is higher than the 2002 rate primarily due to the increase in expected pretax earnings. Higher pretax earnings reduces the positive impact of these fixed foreign deductions.
Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes(“SFAS No. 109”), requires that the tax benefit of available tax carryforwards be recorded as an asset to the extent that management assesses the utilization of such carryforwards to be “more likely than not”. When the future utilization of some portion of the carryforwards is determined not to be “more likely than not”, SFAS No. 109 requires that a valuation allowance be provided to reduce the recorded tax benefits from such assets.
Included as deferred tax assets at March 31, 2003, were approximately $242 million of tax related carryforwards. The carryforwards include U.S. federal net operating loss carryforwards, the majority of which do not begin to expire until 2008, U.S. state net operating loss carryforwards which expire primarily between 2003 and 2016, Canadian carryforwards which expire primarily in 2008, International carryforwards which have no expiration and minimum tax credits which have no expiration. Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2003 and 2008. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, Devon’s management believes that
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Results of Discontinued Operations.Under the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, Devon reclassified its Indonesian, Argentine and Egyptian activities as discontinued operations. The decrease in earnings from discontinued operations before income taxes and the related income taxes from first quarter 2002 to first quarter 2003 was primarily due to the sale of these operations during 2002.
Cumulative Effect of Change in Accounting Principle. At the time of adoption of SFAS No. 143 Devon recorded a cumulative-effect-type adjustment for a charge to net earnings of $16 million net of deferred taxes of $10 million.
Capital Expenditures, Capital Resources and Liquidity
The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in Part 1, Item 1.
Capital Expenditures.Approximately $512 million was spent in the first three months of 2003 for capital expenditures. This total includes $471 million for the acquisition, drilling or development of oil and gas properties. These amounts compare to first quarter 2002 capital expenditures of $2.2 billion. This total includes $1.7 billion related to the January 2002 Mitchell acquisition and $463 million for the acquisition, drilling or development of oil and gas properties.
Other Cash Uses.Devon’s common stock dividends were $8 million in each of the first quarters of 2003 and 2002. Devon also paid $2 million of preferred stock dividends in each of the first quarters of 2003 and 2002.
Devon’s primary source of liquidity has historically been net cash provided by operating activities. This source has been supplemented as needed by accessing credit lines and commercial paper markets and issuing equity securities and long-term debt securities.
Net cash provided by operating activities (“operating cash flow”) continued to be the primary source of capital and liquidity in the first quarter of 2003. Operating cash flow in the first quarter of 2003 was $827 million, compared to $368 million in the first quarter of 2002. The increase in operating cash flow in the 2003 quarter was primarily caused by the increase in revenues partially offset by increased expenses, as discussed earlier in this section.
Devon’s operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond Devon’s control and are difficult to predict.
To mitigate some of the risk inherent in oil and natural gas prices, Devon has entered into various fixed-price physical delivery contracts and financial price swap contracts to fix the price to be received for a portion of future oil and natural gas production. Additionally, Devon has utilized price collars to set
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In addition to the above quantities, Devon also has fixed-price physical delivery contracts, for the years 2005 through 2011, covering Canadian natural gas production ranging from 8 Bcf to 14 Bcf per year. From 2012 through 2016, Devon also has Canadian gas volumes subject to a fixed-price contract, but the yearly volumes are less than 1 Bcf.
By removing the price volatility from a portion of its oil and natural gas production, Devon has mitigated, but not eliminated, the potential negative effect of declining prices on its operating cash flow.
It is Devon’s policy to only enter into derivative contracts with investment grade rated counterparties deemed by management as competent and competitive market makers.
In December 2002, Devon announced that its capital expenditure budget for the year 2003 was approximately $1.8 billion. As a result of the April 25, 2003 Ocean merger, Devon’s expected capital expenditures will be approximately $2.4 billion in 2003. This capital budget represents the largest planned use of available operating cash flow. To a certain degree, the ultimate timing of these capital expenditures is within Devon’s control. Therefore, if oil and natural gas prices decline to levels below its acceptable levels, Devon could choose to defer a portion of these planned 2003 capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. Based upon current oil and gas price expectations for 2003, Devon anticipates that its operating cash flow will exceed its planned capital expenditures and other cash requirements for the year. Devon currently intends to accumulate any excess cash to fund current and future years’ debt maturities. Additional alternatives could be considered based upon the actual amount, if any, of such excess cash.
Other sources of liquidity are Devon’s revolving lines of credit (the “Credit Facilities”). The Credit Facilities include a U.S. facility of $725 million (the “U.S. Facility”) and a Canadian facility of $275 million (the “Canadian Facility”). On March 31, 2003, there were no borrowings under either the U.S. Facility or the Canadian Facility.
Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Devon has historically elected a rate that is based upon LIBOR, plus a margin dictated by Devon’s debt rating. Borrowings under the Canadian Facility have also been made under a rate based upon the Bankers’ Acceptance rate, plus a margin dictated by Devon’s debt rating. Based upon its current debt rating, Devon can borrow under the Credit Facilities at a rate of between 45 and 125 basis points above LIBOR based upon usage and the tranche utilized, and 72.5 basis points above the Bankers’ Acceptance rate. The Credit Facilities also provide for an annual facility fee of $1.4 million that is payable quarterly.
Devon also has access to short-term credit under its commercial paper program. Total borrowings under the U.S. Facility and the commercial paper program may not exceed $725 million. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days. Devon had no commercial paper debt outstanding at March 31, 2003.
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Devon also has a letter of credit and revolving bank facility (“LOC Facility”) for its Canadian operations. This C$150 million LOC Facility is used primarily by Devon’s wholly-owned subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to issue letters of credit. As of March 31, 2003, C$110 million ($75 million converted to U.S. dollars using the March 31, 2003 exchange rate) of letters of credit were issued under the LOC Facility primarily for Canadian drilling commitments.
Devon has $1.1 billion outstanding under its $3 billion senior unsecured credit facility. This credit facility, which was entered into in October 2001, has a term of five years. The remaining balance outstanding as of March 31, 2003 will mature as follows:
This $3 billion facility includes various rate options which can be elected by Devon, including a rate based on LIBOR plus a margin. As of March 31, 2003, the average interest rate on this facility was 2.4%.
In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51.Interpretation No. 46 requires a company to consolidate a variable interest entity if the company has a variable interest (or combination of variable interests) that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. A direct or indirect ability to make decisions that significantly affect the results of the activities of a variable interest entity is a strong indication that a company has one or both of the characteristics that would require consolidation of the variable interest entity. Interpretation No. 46 also requires additional disclosures regarding variable interest entities. The new interpretation is effective immediately for variable interest entities created after January 31, 2003, and is effective in the first interim or annual period beginning after June 15, 2003, for variable interest entities in which a company holds a variable interest that it acquired before February 1, 2003. Devon owns no interests in variable interest entities, and therefore this new interpretation will not affect Devon’s consolidated financial statements.
During April 2003, the Financial Accounting Standards Board (FASB) issued Statement No. 149,Amendment of Statement 133 on Derivative Instruments and Hedging Activities (“SFAS No. 149”). SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. SFAS No. 149 is generally effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. The guidance should be applied prospectively. The Company will follow the guidance of SFAS No. 149 and expects that it will have no impact on its financial statements.
The information included in “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of Devon’s 2002 Annual Report on Form 10-K is incorporated herein by reference. Such information includes a description of Devon’s potential exposure to market risks, including commodity price risk, interest rate risk and foreign currency risk. As of March 31, 2003, there have been no material changes in Devon’s market risk exposure from that disclosed in the 2002 Form 10-K and the May 8, 2003 Current Report on Form 8-K.
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We maintain disclosure controls and procedures and internal controls designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our principal executive and financial officers have evaluated our disclosure controls and procedures within 90 days prior to the filing of this Quarterly Report on Form 10-Q and have determined that such disclosure controls and procedures are effective.
Subsequent to their evaluation, there were no significant changes in internal controls or other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.
PART II. OTHER INFORMATION
None
(a) Devon’s special meeting of stockholders was held in Oklahoma City, Oklahoma at 10:00 a.m. local time, on Friday April 25, 2003.
(b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities Exchange Act of 1934, as amended.
(c) A total of 126,180,427 shares of Devon’s common stock outstanding and entitled to vote were present at the meeting in person or by proxy, representing approximately 81% percent of the total outstanding. The matters voted upon were as follows:
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(a) Exhibits required by Item 601 of Regulation S-K are as follows:
(b) Reports on Form 8-K
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SIGNATURES
Pursuant to the requirements 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.
Date: May 13, 2003
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CERTIFICATION
I, J. Larry Nichols, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Devon Energy Corporation;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):
6. The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
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I, William T. Vaughn, certify that:
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INDEX TO EXHIBITS