Item 1.
Business
General
Devon Energy Corporation, including its subsidiaries, (“Devon”) is an independent energy company engaged primarily in oil and gas exploration, development and production, the acquisition of producing properties, the transportation of oil, gas, and NGLs and the processing of natural gas. Through its predecessors, Devon began operations in 1971 as a privately held company. In 1988, Devon’s common stock began trading publicly on the American Stock Exchange under the symbol “DVN”. In October 2004, Devon transferred its common stock listing to the New York Stock Exchange.
The principal and administrative offices of Devon are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
Devon operates oil and gas properties in the United States, Canada and various regions located outside North America. Devon’s North American properties are concentrated within five geographic areas. Operations in the United States are focused in the Permian Basin, the Mid-Continent, the Rocky Mountains and onshore and offshore Gulf Coast. Canadian properties are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. Properties outside North America are located primarily in Azerbaijan, China, Egypt, and areas in West Africa, including Equatorial Guinea, Gabon and Cote d’Ivoire. In addition to its oil and gas operations, Devon has marketing and midstream operations. These include marketing natural gas, crude oil and NGLs, and the construction and operation of pipelines, storage and treating facilities and gas processing plants. (A detailed description of Devon’s significant properties and associated 2004 developments can be found under “Item 2.
Item 2.
Properties
Substantially all of Devon’s properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in Devon’s core operating areas. These interests entitle Devon to drill for and produce oil, natural gas and NGLs from specific areas. Devon’s interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral and net profits interests, foreign government concessions and other forms of direct and indirect ownership in oil and gas properties.
Devon also has certain midstream assets, including natural gas and NGL processing plants and pipeline systems. Devon’s most significant midstream assets are its Bridgeport assets serving the Barnett Shale development in North Texas. These assets include approximately 2,400 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.
Proved Reserves and Estimated Future Net Revenue
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir. The reserve estimates for a given reservoir may change substantially over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur in the future.
Devon’s policies regarding booking reserves (1) require proved reserves to be in compliance with the SEC definitions and guidance and (2) assign responsibilities for reserves bookings to Devon’s Reserve Evaluation Group (the “Group”). The policies also require that reserve estimates be made by qualified reserves estimators (“QREs”), as defined by the Society of Petroleum Engineers’ standards. A list of QREs is kept by the Senior Advisor - Corporate Reserves. All QREs are required to receive education covering the fundamentals of SEC proved reserves assignments.
The Group is responsible for internal reserves evaluation and certification and includes the Manager - E&P Budgets and Reserves and the Senior Advisor - Corporate Reserves. The Group reports independently of any of Devon’s operating divisions. The Vice President - Planning and Evaluation is directly responsible for overseeing the Group and reports to the President of Devon.
No portion of the Group’s compensation is dependent on the quantity of reserves booked.
Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major changes (additions and revisions) to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants as discussed below.
In addition to internal audits, Devon engages three independent petroleum consulting firms to perform both external reserves preparation and audits. Ryder Scott Company, L.P. prepared the reserves estimates for all offshore Gulf of Mexico properties and for 98% of the international proved reserves. LaRoche Petroleum Consultants, Ltd. audited the reserves estimates for about 73% of the domestic onshore properties. AJM Petroleum Consultants prepared estimates covering 22% of Devon’s Canadian reserves.
Set forth below is a summary of the reserves which were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2004, 2003 and 2002.
“Prepared” reserves are those estimates of quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves which were estimated by Devon employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.
Devon follows what it believes to be a rational approach not only to recording oil and gas reserves, but also to subjecting these reserves to reviews by independent petroleum consultants. As discussed above, the reserve estimates for all of our Gulf of Mexico and international properties are prepared by an independent petroleum consulting firm every year (excluding 2% of Devon’s 2004 and 2003 international reserves that were estimated by in-house engineers). Additionally, in Canada an independent petroleum consulting firm prepares approximately a rolling one-third of our properties each year so that the reserve estimates for substantially all the Canadian properties are prepared by outside engineers over a three-year cycle.
For the U.S. onshore properties, reserve estimates of individually significant properties are either prepared or audited by an independent petroleum consulting firm, while estimates of minor properties are prepared by in-house engineers. This approach results in independent engineers preparing or auditing over 50% of our U.S. onshore reserves each year.
Over any three-year period, more than 95% of Devon’s company-wide reserve estimates are prepared or audited by an independent petroleum consulting firm. Devon believes this approach provides a high degree of assurance about the validity of our reserve estimates. This is evidenced by the fact that in the past five years, Devon’s annual revisions to its reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 2% of the previous year’s estimate.
In addition to internal and external reviews, three independent members of Devon’s Board of Directors have been assigned to a Reserves Committee. The Reserves Committee assists the Board of Directors with the oversight of (1) the annual review and evaluation of Devon’s consolidated oil, gas and NGL reserves; (2) the integrity of Devon’s reserves evaluation and reporting system; (3) Devon’s compliance with legal and regulatory requirements related to reserves evaluation, preparation, and disclosure; (4) the qualifications and independence of Devon’s independent engineering consultants; and (5) Devon’s business practices and ethical standards in relation to the preparation and disclosure of reserves. The Reserves Committee meets at lease twice a year to discuss reserves issues and policies and periodically meets separately with Devon’s senior reserves engineering personnel and its independent petroleum consultants.
The following table sets forth Devon’s estimated proved reserves and the related estimated pre-tax future net revenues, pre-tax 10% present value and after-tax standardized measure of discounted future net cash flows as of December 31, 2004. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 18 to Devon’s Consolidated Financial Statements included herein.
(1)
Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. NGL reserves are converted to Boe on a one-to-one basis with oil. The respective
prices of gas and oil are affected by market conditions and other factors in addition to relative energy content.
(2)
Estimated future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to non-property related expenses such as debt service and future income tax expense or to depreciation, depletion and amortization.
These amounts were calculated using prices and costs in effect as of December 31, 2004. These prices were not changed except where different prices were fixed and determinable from applicable contracts. Such contracts include derivatives accounted for as cash flow hedges. These assumptions yield average prices over the life of Devon’s properties of $34.69 per Bbl of oil, $5.27 per Mcf of natural gas and $29.73 per Bbl of NGLs. These prices compare to December 31, 2004, New York Mercantile Exchange prices of $43.45 per Bbl for crude oil and $6.18 per MMBtu for natural gas.
Devon believes that the pre-tax 10% present value is a useful measure in addition to standardized measure as it assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors which are consistent from company to company. We also understand that securities analysts use this measure in similar ways.
(3)
See Note 18 to the consolidated financial statements included in Item 8 of this report.
As presented in the previous table, Devon had 1,652 MMBoe of proved developed reserves at December 31, 2004. Proved developed reserves consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding Devon’s proved developed reserves at December 31, 2004.
No estimates of Devon’s proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of the last fiscal year except (i) in filings with the SEC and (ii) in filings with the Department of Energy (“DOE”). Reserve estimates filed by Devon with the SEC correspond with the estimates of Devon reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Devon’s reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that Devon operates and to exclude all interests in wells that Devon does not operate.
The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 2004. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
Production, Revenue and Price History
Certain information concerning oil, natural gas and NGL production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 2004, is set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Well Statistics
The following table sets forth Devon’s producing wells as of December 31, 2004:
(1)
Gross wells are the total number of wells in which Devon owns a working interest.
(2)
Net refers to gross wells multiplied by Devon’s fractional working interests therein.
Developed and Undeveloped Acreage
The following table sets forth Devon’s developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2004.
(1)
Gross acres are the total number of acres in which Devon owns a working interest.
(2)
Net refers to gross acres multiplied by Devon’s fractional working interests therein.
Operation of Properties
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions.
Devon is the operator of 19,506 of its wells. As operator, Devon receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting its financial data, Devon records the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.
Organization Structure
Devon’s North American properties are concentrated within five geographic areas. Operations in the United States are focused in the Permian Basin, the Mid-Continent, the Rocky Mountains and onshore and offshore Gulf Coast regions. Canadian properties are focused in the Western Canadian Sedimentary Basin in Alberta and British Columbia. Properties outside North America are located primarily in Azerbaijan, China, Egypt and areas in West Africa, including Equatorial Guinea, Gabon, and Cote d’Ivoire. Additionally, Devon has exploratory interests, but no current producing assets, in other international countries including Angola, Brazil, Nigeria and Syria. Maintaining a tight geographic focus in selected core areas has allowed Devon to improve operating and capital efficiency.
The following table sets forth proved reserve information on the most significant geographic areas in which Devon’s properties are located as of December 31, 2004.
(1)
Gas reserves are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. NGL reserves are converted to Boe on a one-to-one basis with oil. The respective prices of gas and oil are affected by market and other factors in addition to relative energy content.
(2)
Percentage which MMBoe for the basin or region bears to total MMBoe for all proved reserves.
(3)
Determined in accordance with Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities (“SFAS No. 69”), except that no effect is given to future income taxes. See a discussion of the difference between the pre-tax 10% present value and standardized measure in footnote 2 of “Item 2. Properties - Proved Reserves and Estimated Future Net Revenues.”
(4)
Percentages which present value for the basin or region bears to total present value for all proved reserves.
(5)
Determined in accordance with SFAS No. 69.
(6)
Canadian dollars converted to U.S. dollars at the rate of $1 Canadian: $0.8308 U.S.
United States
The following descriptions of Devon’s properties in the United States are as of December 31, 2004. Devon plans to divest certain of these properties in 2005. Information provided below may be materially different after the planned divestitures.
Permian Basin
Devon’s Permian Basin assets are located in portions of Southeast New Mexico and West Texas. These assets include conventional oil and gas properties producing from a wide variety of geologic formations and depths. The Permian Basin represented 9% of Devon’s proved reserves at December 31, 2004.
Devon’s leasehold position in Southeast New Mexico encompasses more than 117,000 net acres of developed lands and 231,000 net acres of undeveloped land and minerals. Historically, Devon has been a very active operator in this area, developing gas from the high productivity Morrow formation and oil in the lower risk Delaware formation.
In the West Texas portion of the Permian Basin, Devon maintains a base of oil production with long-life reserves. Many of these reserves are from both operated and non-operated positions in large enhanced oil recovery units such as the Wasson ODC Unit, the Willard Unit, the Reeves Unit, the North Welch Unit and the Anton Irish (Clearfork) Unit. These oil-producing units often exhibit low decline rates. Devon also owns a significant acreage position in West Texas with over 210,000 net acres of developed lands and over 232,000 net acres of undeveloped land and minerals at December 31, 2004.
Mid-Continent
The Mid-Continent region includes portions of Texas, Oklahoma and Kansas. These areas encompass a wide variety of geologic formations and productive depths and produce both oil and natural gas. Devon’s Mid-Continent production has historically come from conventional oil and gas properties. However, the Barnett Shale in North Texas, acquired by Devon in 2002, is a non-conventional gas resource. The Mid-Continent region represented 20% of Devon’s proved reserves at December 31, 2004. Approximately 77% of Devon’s proved reserves in the Mid-Continent area are in the Barnett Shale.
The Barnett Shale, Devon’s largest producing field, is known as a tight gas formation. This means that in its natural state, the formation is resistant to the production of natural gas. However, the application of available technology has made the Barnett Shale a low-risk and highly profitable natural gas operation. Devon holds 535,000 net acres and over 1,900 producing wells in the Barnett Shale. Devon’s average working interest is approximately 95%.
Devon has experienced success extracting gas from the Barnett Shale by using light sand fracturing. Light sand fracturing yields better results than earlier techniques, is less expensive and can be used to complete new wells and to refracture existing wells to increase production rates. Devon is also applying horizontal drilling, closer well spacing and reservoir optimization techniques to further enhance the value of the Barnett Shale.
Devon’s marketing and midstream operations gather and process its Barnett Shale production along with Barnett Shale production from unrelated third parties. The gathering system consists of approximately 2,400 miles of pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL fractionator.
In 2005, Devon plans to drill a total of 226 new Barnett Shale wells including 156 horizontals and 70 verticals. About two-thirds of the horizontal wells will be drilled outside the core development area in an effort to further expand the productive area of the field. The Barnett Shale is expected to continue to be an important producing area for Devon for the foreseeable future. Current net production from the Barnett Shale is approximately 93 MBoe per day.
Rocky Mountain
Devon’s operations in the Rocky Mountain region include properties in Wyoming, Montana, Utah, and Northern New Mexico. These assets include conventional oil and gas properties and coalbed natural gas projects. As of December 31, 2004, the Rocky Mountain region comprised 9% of Devon’s proved reserves.
Approximately 19% of Devon’s proved reserves in the Rocky Mountains are from coalbed natural gas. Devon began producing coalbed natural gas in the San Juan Basin of New Mexico in the mid-1980s and began drilling coalbed natural gas wells in the Powder River Basin of Wyoming in 1998. As of December 31, 2004, Devon had approximately 1,360 producing coalbed natural gas wells in the Powder River Basin. Devon’s net coalbed natural gas production from the basin was approximately 76 MMcf per day as of December 31, 2004. Devon plans to drill 120 new wells and deepen 44 existing wells in the Powder River Basin in 2005. Current production in the basin is primarily from the Wyodak coal formation. Development of the deeper Big George formation is expanding the play into the western portion of the Powder River Basin. Devon also plans to plug and abandon 100 wells in the Powder River Basin in 2005.
Devon’s most significant conventional gas project in the Rocky Mountain region is the Washakie field in Wyoming. Devon is continuing to develop and grow production from this field. In 2004, Devon added 62 producing wells in the Washakie field and plans to drill another 84 wells in 2005. Devon has interests in over 200,000 gross acres and an inventory of more than 300 drilling locations. Devon’s current net production from Washakie is approximately 15 MBoe per day.
Gulf Coast Onshore
Devon’s Gulf Coast onshore properties are located in South and East Texas, Louisiana and Mississippi. Most of the wells in the region are completed in conventional sandstone formations. At December 31, 2004, the Gulf Coast accounted for approximately 12% of Devon’s proved reserves.
Devon’s operations in South Texas have focused on exploration in the Edwards, Wilcox and Frio/ Vicksburg formations. Devon has high working interests, up to 100%, in several producing fields.
East Texas is an important conventional gas producing region for Devon. Carthage and Groesbeck are two of the primary producing areas. Wells produce from the Cotton Valley sands, the Travis Peak sands and from shallower sands and carbonates. Devon has interests in nearly 1,900 producing wells in East Texas and plans to drill 106 wells in Carthage and 37 wells in Groesbeck in 2005. Devon’s current net production from East Texas is about 42 MBoe per day.
Gulf Offshore
The offshore Gulf of Mexico accounted for 16% of Devon’s 2004 production and 8% of year-end proved reserves. Devon is among the largest independent oil and gas producers in the Gulf of Mexico and operates 450 platforms and caissons. Gulf of Mexico operations are typically differentiated by water depth. The shelf is defined by water depths of 600 feet or less. The deep water is at depths beyond 600 feet. Devon operates in both the shelf and deepwater areas. However, Devon expects to divest a significant number of its Gulf of Mexico shelf producing assets in 2005.
In 2004, Devon commenced production from two new deepwater fields. Red Hawk (Garden Banks 876) commenced production in July and is currently producing in excess of 120 MMcf of gas per day. Devon has a 50% working interest in Red Hawk. Magnolia (Garden Banks 783) began producing oil and gas in December. In February 2005, Magnolia was producing about 7 MBoe per day net to Devon’s 25% working interest from two of an expected eight total producing wells.
In addition to its producing properties, Devon has a significant inventory of exploration prospects in the Gulf of Mexico. Devon has an interest in 85 undeveloped blocks on the shelf and 526 undeveloped deepwater blocks.
On the shallow-water shelf, the industry is beginning to explore for oil and gas reserves at depths in excess of 15,000 feet. Devon has an interest in 28 of these “deep shelf” prospects and expects to drill as many as 8 deep shelf exploratory wells during 2005.
In the deepwater Gulf of Mexico, almost all historical production of oil and gas has been from Miocene aged reservoirs. Devon currently produces approximately 55 MBoe per day from the deepwater Gulf and has an inventory of 18 undrilled Miocene prospects. During 2005, Devon expects to drill exploratory wells on four Miocene prospects.
In recent years, the industry has begun to explore for oil below the Miocene in older formations that are collectively referred to as the “lower Tertiary.” To date, Devon has participated in three lower Tertiary discoveries and has an interest in 23 additional undrilled lower Tertiary prospects.
Cascade (Walker Ridge 206) was drilled in 2002 and was Devon’s first discovery in the lower Tertiary trend. Devon has a 25% working interest in the discovery and expects to drill an appraisal well on the prospect in 2005. Devon’s second lower tertiary discovery was in 2003 at St. Malo (Walker Ridge 678). During 2004, Devon appraised the St. Malo discovery with a second well. The St. Malo appraisal well encountered more than 400 net feet of oil pay. Devon has a 22.5% working interest in
St. Malo and plans to drill a second appraisal well on the St. Malo prospect in 2005. In 2004, Devon drilled its third lower Tertiary discovery at Jack (Walker Ridge 759). The Jack well encountered more than 350 net feet of oil pay. Devon has a 25% working interest in Jack and plans to drill an appraisal well on the prospect in 2005. In addition, Devon plans to test at least one additional lower Tertiary prospect during 2005.
Canada
Devon is among the largest independent oil and gas producers in Canada and operates in most of the producing basins in Western Canada. As of December 31, 2004, 29% of Devon’s proved reserves were Canadian. Devon’s Canadian assets will be reduced by the planned 2005 non-core property divestiture program.
Many of the Canadian basins where Devon operates are accessible for drilling only in the winter when the ground is frozen. Consequently, the winter season, from December through March, is the most active drilling period. Devon expects to drill about 400 wells in the 2004-2005 winter program and spend $475 million, or nearly half of the full year Canadian capital budget.
The Deep Basin in West-Central Alberta accounted for 16% of Devon’s Canadian proved reserves at December 31, 2004. Devon holds 480,000 net undeveloped acres in the Deep Basin, where it drilled 187 wells in 2004 and has another very active drilling program planned for 2005. The profitability of Devon’s operations in the Deep Basin is enhanced by its ownership in nine gas processing plants in the area. Deep Basin reservoirs tend to be rich in liquids, producing up to 50 barrels of NGLs with each MMcf of gas.
Other important conventional oil and gas exploration and development areas for Devon in Canada include the Peace River Arch, Northeast British Columbia and the Central Plains. Devon drilled 149, 115 and 90 wells, respectively, in these areas in 2004.
Devon also drills for and produces “cold-flow” heavy oil in the Lloydminster area of Alberta and Saskatchewan where oil is found in multiple horizons generally at depths of 1,000 to 2,000 feet. Lloydminster accounted for 12% of Devon’s 2004 Canadian proved reserves.
The oil sands of Eastern Alberta are a vast North American hydrocarbon resource. Devon holds over 140,000 net acres of oil sands leases in Alberta. In December 2004, Devon received final regulatory approval to proceed with development of its Jackfish oil sands project, in which Devon has a 100% working interest. The project is expected to produce 35 MBbls per day of thermal heavy oil when fully operational in 2008. Devon expects to invest $195 million at Jackfish in 2005 for site preparation, facilities construction and initial well drilling. Devon also owns interests in the Surmont and Dover oil sands projects which are among those expected to be divested in 2005.
International
In addition to its core properties in the United States and Canada, Devon also looks outside North America for longer-term reserve and production growth. At December 31, 2004, these international areas accounted for 13% of Devon’s worldwide proved reserves.
The most significant international producing property is the ExxonMobil-operated Zafiro oil field on Block B, offshore Equatorial Guinea in West Africa. During 2004, Devon’s share of production from Zafiro averaged 47 MBbls per day. Devon’s share of production from Zafiro is expected to be reduced by about 20% in 2005. The expected reduction is the result of field decline and a change in Devon’s share of production under the terms of the production sharing contract.
Devon will continue drilling development wells on Block B in 2005. Devon has also identified exploratory prospects on Block B and on three additional blocks in Equatorial Guinea in which it has interests. Exploratory wells on Blocks B and P are planned for 2005.
Devon also has active offshore exploration programs in other countries in West Africa and Brazil. Devon made a discovery in 2004 offshore Brazil on Block BM-C-8 and plans follow-up drilling in 2005. Devon also plans to drill potentially high-impact exploratory wells offshore Nigeria and Angola in 2005.
Devon’s second most significant international producing asset is its Panyu project offshore China. Panyu, in the Pearl River Mouth of the South China Sea, was discovered in 1998. Panyu production began late in 2003. Field production peaked in 2004 and averaged about 19 MBbls per day to Devon’s interest during the year. Devon plans to drill and complete up to 10 additional development wells and test two or three exploratory prospects in the area during 2005. Devon expects its net production from Panyu to average about 15 MBbls per day in 2005.
In Azerbaijan, Devon has a 5.6% carried working interest in the Azeri-Chirag-Gunashli, or ACG, oil development project in the Caspian Sea. Devon estimates that the ACG field contains over 4.7 billion barrels of gross proved oil reserves. Oil production from the ACG field will increase dramatically upon completion of the Baku-T’Bilisi-Ceyhan pipeline, which is expected in 2005. Devon’s net share of ACG production is expected to peak between 40,000 to 50,000 barrels per day in 2008 or 2009.
Devon also holds interests in Cote d’Ivoire, Gabon, Ghana, Egypt, Russia, Indonesia and Syria. In 2004, Devon entered into several joint ventures with partners to test Devon’s exploratory acreage in Egypt.
Title to Properties
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. Devon believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Item 3.
Item 3.
Legal Proceedings
Royalty Matters
Numerous gas producers and related parties, including Devon, have been named in various lawsuits 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 principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Trial is set for February 2007 if the suit continues to advance. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.
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. 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.
Tax Treatment of Exchangeable Debentures
As described more fully in Note 8 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report, Devon has certain exchangeable debentures, with a principal amount totaling $760 million, which are exchangeable at the option of the holders into shares of ChevronTexaco common stock owned by Devon. The debentures were assumed, and the ChevronTexaco common stock was acquired, by Devon in the 1999 PennzEnergy merger.
The Internal Revenue Service (“IRS”) recently examined the 1998 income tax return of PennzEnergy’s predecessor, and the IRS formally notified Devon in April 2004 that it disagreed with certain tax treatments of the exchangeable debentures and similar exchangeable debentures retired in 1998. Devon did not agree with the IRS positions and contested the claim of additional taxes. In June 2004, Devon formally protested the IRS notice and requested a conference with the IRS Appeals Office. A preliminary appeals conference was held in October 2004, and additional appeals meetings were held in November and December 2004. This matter was resolved in February 2005, when the IRS agreed with Devon and concluded that no taxes were due.
Other Matters
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.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the fourth quarter of 2004.
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Price
Devon’s common stock has been traded on the New York Stock Exchange (the “NYSE”) since October 12, 2004. Prior to October 12, 2004, Devon’s common stock was traded on the American Stock Exchange (the “AMEX”). From December 15, 1998 to August 27, 2004, a class of Devon exchangeable shares traded on The Toronto Stock Exchange under the symbol “NSX”. These shares were essentially equivalent to Devon common stock and were exchangeable at any time, on a one-for-one basis, for common shares of Devon at the holder’s option. The last remaining exchangeable shares outstanding were exchanged for Devon common stock on August 27, 2004.
The following table sets forth the high and low sales prices for Devon common stock as reported by the NYSE and AMEX for the periods indicated.
On February 28, 2005, there were 18,623 holders of record of Devon common stock.
Dividends
Devon commenced the payment of regular quarterly cash dividends on its common stock on June 30, 1993, in the amount of $0.015 per share. Effective December 31, 1996, Devon increased its quarterly dividend payment to $0.025 per share. Effective March 31, 2004, Devon increased its quarterly dividend payment to $0.05 per share. Effective March 31, 2005, Devon will increase the quarterly dividend payment to $0.075 per share. Devon anticipates continuing to pay regular quarterly dividends in the foreseeable future.
Issuer Purchases of Equity Securities
The following table sets forth information with respect to repurchases by Devon of its shares of common stock during the fourth quarter of 2004.
(1)
On September 27, 2004 Devon announced its plan to repurchase up to 50 million shares of its common shares. The repurchase program does not obligate Devon to acquire any specific number of shares and may be discontinued at any time. All repurchases under the program shall be completed on or before December 31, 2006.
Item 6.
Item 6.
Selected Financial Data
The following selected financial information (not covered by the independent auditors’ report) should be read in conjunction with “Item 1. Business - Development of Business,” “Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses changes in Devon’s financial condition and results of operations during the three-year period of 2002 through 2004. Reference is made to “Item 6. Selected Financial Data” and “Item 8. Financial Statements and Supplementary Data.”
Overview
According to most key financial and operating measures, 2004 was the best year in Devon’s history. We delivered record production, earnings, earnings per share and cash flow from operations. Additionally, our drilling program was very successful.
We produced 251 million Boe in 2004, representing a 10% increase over our 2003 production of 228 million Boe. The largest contributor to this growth was the merger with Ocean in April 2003. With four additional months of production in 2004, the Ocean merger generated 21 million Boe of the year-over-year growth. Additionally, production in China began in the fourth quarter of 2003 and contributed seven million Boe of 2004 growth. These increases were partially offset by a decline in offshore Gulf of Mexico production due to the effects of Hurricane Ivan and natural production declines on certain other properties.
In 2004, we also delivered the highest net earnings, $2.2 billion, and earnings per diluted share, $4.38, in our 16 years as a public company. With an increase in production and increases in average realized commodity prices, Devon’s oil, gas and NGL revenues climbed 27% to almost $7.5 billion. Also contributing to the growth in earnings, our marketing and midstream margin grew 26% to $362 million in 2004 primarily due to higher realized prices for natural gas and NGLs.
Record production and revenues were partially offset by higher operating expenses in 2004. The primary factors driving the increases in expenses were increased operations due to the Ocean merger, increased well workover activity, the weakening of the U.S. dollar versus the Canadian dollar and increased production taxes. The higher production taxes tracked our increase in commodity revenues. Although most expenses increased, general and administrative expenses decreased 10% as a result of the realization of overhead and personnel efficiencies following the Ocean merger.
In addition to generating record earnings in 2004, Devon also delivered record cash flow from operations. At $4.8 billion, our 2004 cash flow from operations represents a 28% increase over 2003. This all-time high amount was used to fund a $3.1 billion capital expenditure program, $973 million of debt repayments, $189 million of common stock repurchases and $107 million of dividend payments. At December 31, 2004, we had $2.1 billion of cash and short-term investments. This amount is adequate to cover debt maturities through 2007.
Furthermore, on September 27, 2004, Devon announced two key initiatives aimed at creating additional value for its stockholders. First, we announced a property divestiture program. The sales of non-core properties located in Canada, the onshore U.S. and in the Gulf of Mexico are expected to generate $1.0 to $1.5 billion in after-tax proceeds. Closings are expected in the first half of 2005. Second, we announced a stock repurchase program. With cash flow from operations and proceeds from the planned sales of oil and gas properties, we intend to repurchase up to 50 million shares of our common stock. Through February 28, 2005, we had repurchased 12.5 million shares at a total cost of $501 million.
In 2004, we declared a two-for-one stock split and moved our stock listing to the New York Stock Exchange. At its March 2005 meeting, Devon’s Board of Directors approved the increase of the quarterly cash dividends from $0.05 per share to $0.075 per share. The increase is effective March 31, 2005.
Oil, gas and NGL prices and, therefore, oil, gas and NGL revenues are influenced by many factors outside of our control. Consequently, Devon’s management has focused its efforts on increasing oil and gas reserves and production and controlling costs. Devon’s future earnings and cash flows are dependent on our ability to continue to contain our overall cost structure at a level that will allow for profitable production. As a result, Devon has established a foundation of core assets in North America that can consistently deliver cost-efficient drill-bit growth and provide a strong source of free cash flow. We balance this foundation of core assets with measured investment in high-impact projects in the deepwater Gulf of Mexico and international arenas.
During 2004, Devon drilled 274 exploration wells and over 1,900 development wells, and we incurred $2.9 billion in costs related to oil and gas property acquisition, exploration, and development activities. With an overall drilling success rate of 96%, reserves grew 268 million Boe from discoveries and extensions. Another 45 million Boe of reserves were added to Devon’s reserve base from performance revisions. These 2004 drilling results are evidence of our success in lowering the costs of adding proved reserves.
At December 31, 2004, our proved reserves totaled 2.1 billion Boe. Although reserve additions due to discoveries, extensions and performance revisions outpaced 2004 production, reserves at December 31, 2004 were relatively flat compared to December 31, 2003. This resulted from negative price revisions which reduced reserves by 76 million Boe.
To estimate reserves, accounting rules dictate that prices in effect as of the last day of the period are held constant indefinitely. As a result, two primary factors caused the negative price revisions at December 31, 2004. First, Devon’s reserves under certain international production sharing contracts are based in part on the amount of revenue needed to recover our costs. Therefore, as prices increase, as was the case for Brent prices at December 31, 2004 compared to December 31, 2003, our international reserves associated with production sharing contracts decrease. Second, heavy oil differentials in Canada widened to over 54% of the NYMEX price at December 31, 2004 compared to a historical average of approximately 30%. Both circumstances were the primary causes of the 2004 negative price revisions.
While Devon has consistently increased production over time, volatility in oil, gas and NGL prices has resulted in considerable variability in earnings and cash flows. Prices for oil, gas and NGLs are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and worldwide economic activity, weather and other factors that are beyond our control. Market conditions, among other factors, will continue to impact Devon’s future earnings and cash flows.
Like all oil and gas exploration and production companies, Devon faces the challenge of natural production decline. As virgin reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and gas exploration and production company depletes part of its asset base with each unit of oil or gas it produces. Historically, we have been able to overcome this natural decline by adding, through drilling and acquisitions, more reserves than we produce. Devon’s future growth will depend on our ability to continue to add reserves in excess of production.
In summary, 2004 was a successful year for Devon and its stockholders, and the outlook for 2005 is promising as well. Devon’s base of core North American resources continues to deliver strong production growth, high margins and attractive returns. Our exploration weighted activities in the Gulf of Mexico and in our international division will expose stockholders to meaningful value creation opportunities. Devon’s financial position provides the flexibility to simultaneously invest in exploration and development projects, retire debt, repurchase stock and, as was recently approved, increase cash dividends in 2005.
Results of Operations
Revenues
Changes in oil, gas and NGL production, prices and revenues from 2002 to 2004 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)
(1)
Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil. The respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content.
(2)
All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
N/M Not meaningful.
The average prices shown in the preceding tables include the effect of Devon’s oil and gas price hedging activities. Following is a comparison of Devon’s average prices with and without the effect of hedges for each of the last three years.
Oil Revenues
2004 vs. 2003 Oil revenues increased $614 million in 2004. An increase in 2004 production of 16 million barrels caused oil revenues to increase by $415 million. The April 2003 Ocean merger accounted for 14 million barrels of increased production. The remaining increase is primarily related to new production from China partially offset by natural production declines and the effects of Hurricane Ivan on Devon’s domestic properties. Oil revenues increased $199 million due to a $2.55 increase in the average realized price of oil.
2003 vs. 2002 Oil revenues increased $679 million in 2003. An increase in 2003 production of 20 million barrels caused oil revenues to increase by $436 million. The April 2003 Ocean merger accounted for 25 million barrels of increased production, partially offset by production lost from the 2002 property divestitures of 5 million barrels. Oil revenues increased $243 million due to a $3.92 increase in the average price of oil.
Gas Revenues
2004 vs. 2003 Gas revenues increased $835 million in 2004. A $0.81 per Mcf increase in the average gas price caused revenues to increase by $714 million. An increase in 2004 production of 28 Bcf caused gas revenues to increase by $121 million. The April 2003 Ocean merger accounted for 43 Bcf of increased production. This was offset by a production decrease in Devon’s domestic properties as a result of natural declines and the effects of Hurricane Ivan.
2003 vs. 2002 Gas revenues increased $1.8 billion in 2003. A $1.71 per Mcf increase in the average gas price caused revenues to increase by $1.5 billion. An increase in 2003 production of 102 Bcf caused gas revenues to increase by $287 million. The April 2003 Ocean merger and January 2002 Mitchell merger accounted for 113 Bcf and 11 Bcf of increased production, respectively, partially offset by production lost from the 2002 property divestitures of 36 Bcf. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties.
NGL Revenues
2004 vs. 2003 NGL revenues increased $147 million in 2004. A $4.39 per barrel increase in average NGL prices caused revenues to increase by $106 million. An increase in 2004 production of 2 million barrels caused revenues to increase $41 million. The April 2003 Ocean merger accounted for 0.6 million barrels of increased production. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties.
2003 vs. 2002 NGL revenues increased $132 million in 2003. A $4.60 per barrel increase in average NGL prices caused revenues to increase by $100 million. An increase in 2003 production of 3 million barrels caused revenues to increase $32 million. The April 2003 Ocean merger and January 2002 Mitchell merger each accounted for 1 million barrels of increased production, partially offset by production lost from the 2002 property divestitures of 1 million barrels. The remaining production increase was primarily related to new drilling and development in the Barnett Shale properties.
Marketing and Midstream Revenues
2004 vs. 2003 Marketing and midstream revenues increased $241 million in 2004. Of this increase, approximately $218 million was the result of higher overall market prices for natural gas and NGLs. Additionally, revenues increased $103 million due to higher third-party natural gas and NGL throughput volumes. This was partially offset by $80 million in lower revenues resulting primarily from the sale of certain assets in 2004.
2003 vs. 2002 Marketing and midstream revenues increased $461 million in 2003. Of this increase, approximately $439 million was the result of higher overall market prices for natural gas and NGLs. Additionally, revenues increased $22 million due to higher third-party natural gas and NGL throughput volumes. The increase in volumes was primarily related to new drilling and development in the Barnett Shale properties and an additional 24 days of production in 2003 due to the timing of the January 2002 Mitchell merger, partially offset by volumes lost as a result of processing plant dispositions.
Operating Costs and Expenses
The details of the changes in operating costs and expenses between 2002 and 2004 are shown in the table below.
(1)
Though per Boe amounts for these expense items may be helpful for profitability trend analysis, these expenses are not directly attributable to production volumes.
(2)
All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
N/M
Not meaningful.
Oil, Gas and NGL Production and Operating Expenses
2004 vs. 2003 Lease operating expenses increased $202 million in 2004. The April 2003 Ocean merger accounted for $84 million of the increase. Lease operating expenses on our historical properties increased $88 million, due to an increase in well workover expenses, ad valorem taxes and power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $30 million increase in costs.
The increase in lease operating expenses per Boe is primarily related to increased well workover expenses, ad valorem taxes and power, fuel and repairs and maintenance costs, as well as the changes in the Canadian-to-U.S. dollar exchange rate. With the increase in oil, gas and NGL prices, more well workovers and repairs and maintenance costs are performed to either maintain or improve production volumes. The higher prices also resulted in increased power and fuel costs.
Production taxes increased $51 million in 2004. The majority of Devon’s production taxes are assessed on our onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 22% increase in domestic oil, gas and NGL revenues was the primary cause of the production tax increase.
2003 vs. 2002 Lease operating expenses increased $303 million in 2003. The April 2003 Ocean merger accounted for $199 million of the increase. Lease operating expenses on our historical properties increased $120 million, due to an increase in well workover expenses and power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $44 million increase in costs. These increases were partially offset by a decrease of $60 million due to property divestitures in 2002.
The increase in lease operating expenses per Boe is primarily related to increased well workover expenses and power, fuel and repairs and maintenance costs, as well as the changes in the Canadian-to-U.S. dollar exchange rate. With the increase in oil, gas and NGL prices, more well workovers and repairs and maintenance costs are performed to either maintain or improve production volumes. The higher prices also resulted in increased power and fuel costs.
As stated previously, most U.S. production taxes are based on a fixed percentage of revenues. Therefore, the 79% increase in domestic oil, gas and NGL revenues was the primary cause of the $93 million production tax increase.
Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”)
DD&A of oil and gas properties is calculated as the percentage of total proved reserve volumes produced during the year, multiplied by the net capitalized investment plus future development costs in those reserves (the “depletable base”). Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
2004 vs. 2003 Oil and gas property related DD&A increased $473 million in 2004. An increase in the combined U.S., Canadian and international DD&A rate from $7.33 per BOE in 2003 to $8.54 per BOE in 2004 caused oil and gas property related DD&A to increase by $305 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger, negative reserve revisions in Canada and certain international countries subject to production sharing contracts and changes in the Canadian-to-
U.S. dollar exchange rate. A 10% increase in 2004 oil, gas and NGL production caused DD&A to increase $168 million.
2003 vs. 2002 Oil and gas property related DD&A increased $562 million in 2003. An increase in the combined U.S., Canadian and international DD&A rate from $5.88 per BOE in 2002 to $7.33 per BOE in 2003 caused oil and gas property related DD&A to increase by $331 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger, higher finding and development costs and changes in the Canadian-to-U.S. dollar exchange rate. A 21% increase in 2003 oil, gas and NGL production caused DD&A to increase $231 million.
Accretion of Asset Retirement Obligation
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. The initial measurement of the asset retirement obligation is to record a separate liability at its fair value with an offsetting asset retirement cost recorded as an increase to the related property and equipment on the balance sheet. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
Because the asset retirement obligation is recorded at its discounted present value, Devon now records accretion expense to reflect the increase in the asset retirement obligation due to the passage of time. We recorded $44 million and $36 million of such accretion expense during 2004 and 2003, respectively.
Marketing and Midstream Operating Costs and Expenses
2004 vs. 2003 Marketing and midstream operating costs and expenses increased $165 million in 2004. Of this increase, approximately $133 million was the result of an increase in prices paid for gas and NGLs. Additionally, operating costs and expenses increased $106 million due to higher third-party natural gas and NGL throughput volumes. This was partially offset by $74 million in lower costs and expenses resulting primarily from the sale of certain assets in 2004.
2003 vs. 2002 Marketing and midstream operating costs and expenses increased $366 million in 2003. Of this increase, approximately $347 million was the result of an increase in prices paid for gas and NGLs. An increase in third-party processed NGL volumes caused the remaining increase in 2003 costs and expenses. The increase in volumes was primarily related to new drilling and development in the Barnett Shale properties and an additional 24 days of production in 2003 due to the timing of the January 2002 Mitchell merger, partially offset by volumes lost as a result of processing plant dispositions.
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 related to exploration and development activities. 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. Net G&A includes
expenses related to oil, gas and NGL exploration and production activities, as well as marketing and midstream activities. See the following table for a summary of G&A expenses by component.
2004 vs. 2003 Gross G&A increased $25 million. The April 2003 Ocean merger increased gross expenses $27 million primarily due to the inclusion of an additional four months of Ocean activities in 2004 compared to 2003. Also, higher compensation and benefit costs, increased charitable contributions and the abandonment of certain Canadian office space increased gross G&A $26 million, $12 million and $5 million, respectively. During 2004, Devon also incurred $6 million of incremental professional fees related to additional activities performed to comply with the requirements of Section 404 of The Sarbanes-Oxley Act of 2002. Finally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $8 million increase in costs. These increases were partially offset by the synergies obtained from the Ocean merger.
The increase in both capitalized G&A of $32 million and reimbursed G&A of $23 million was primarily related to the increased activity subsequent to the April 2003 Ocean merger.
2003 vs. 2002 Gross G&A increased $137 million. This increase was primarily related to the increased activities resulting from the April 2003 Ocean merger, which added $92 million of costs, and increased compensation and benefit costs. Included in the increase of compensation and benefit costs is $14 million related to an increase in pension related costs.
The increase in capitalized G&A of $43 million was primarily related to the April 2003 Ocean merger. Reimbursed G&A increased $6 million. The increase in reimbursed amounts was primarily related to the April 2003 Ocean merger, partially offset by a decline in reimbursements related to the 2002 property divestitures.
Reduction of Carrying Value of Oil and Gas Properties
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. The ceiling test is imposed separately by country.
In calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. These prices are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Devon has entered into various derivative instruments that are accounted for as cash flow hedges. These instruments, which consist of price swaps and costless price collars, and the related future production volumes, are discussed in Note 12. The effect of these hedges has been considered in calculating the full cost ceiling limitations as of December 31, 2004. These hedges reduced the full cost ceiling limitations for the United States, Canada and Equatorial Guinea as of the end of 2004 by $102 million, $77 million and $76 million, respectively. However, the 2004 capitalized costs in these countries did not exceed the related ceiling limitations, with or without the effects of the hedges.
The calculation also dictates the use of a 10% discount factor. The costs to be recovered are compared to the ceiling on a quarterly basis. If the costs to be recovered exceed the ceiling, the excess is written off as an expense, except as discussed in the following paragraph.
If, subsequent to the end of the quarter but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the quarter.
Under the purchase method of accounting for business combinations, acquired oil and gas properties are recorded at estimated fair value as of the date of purchase. We estimate such fair value using our estimates of future oil, gas and NGL prices. In contrast, the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely. Accordingly, the resulting value from the ceiling calculation is not necessarily indicative of the fair value of the reserves.
An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
During 2003 and 2002, we reduced the carrying value of our oil and gas properties by $68 million and $651 million, respectively, due to the full cost ceiling limitations. The after-tax effects of these reductions in 2003 and 2002 were $36 million and $371 million, respectively. The following table summarizes these reductions by geographic area.
The 2003 reduction in carrying value was related to properties in Egypt, Russia and Indonesia. The Egyptian reduction was primarily due to poor results of a development well that was unsuccessful in the primary objective. Partially as a result of this well, Devon revised Egyptian proved reserves downward. The Russian reduction was primarily the result of additional capital costs incurred as well as an increase in operating costs. The Indonesian reduction was primarily related to an increase in operating costs and a reduction in proved reserves. As a result, our Egyptian, Russian and Indonesian costs to be recovered exceeded the related ceiling value by $26 million, $9 million and $1 million, respectively. These after-tax amounts resulted in pre-tax reductions of the carrying values of our Egyptian, Russian and Indonesian oil and gas properties of $45 million, $19 million and $4 million, respectively, in the fourth quarter of 2003.
Additionally, during 2003, we elected to discontinue certain exploratory activities in Ghana, certain properties in Brazil and other smaller concessions. After meeting the drilling and capital commitments on these properties, we determined that these properties did not meet our internal criteria to justify further investment. Accordingly, we recorded a $43 million charge associated with the impairment of these properties. The after-tax effect of this reduction was $38 million.
The 2002 Canadian reduction was primarily the result of lower prices. The recorded fair values of oil and gas properties added from the Anderson acquisition in 2001 were based on expected future oil and gas prices. These expected prices were higher than the June 30, 2002 prices used to calculate the Canadian ceiling.
Based on oil, natural gas and NGL cash market prices as of June 30, 2002, Devon’s Canadian costs to be recovered exceeded the related ceiling value by $371 million. This after-tax amount resulted in a pre-tax reduction of the carrying value of our Canadian oil and gas properties of $651 million in the second quarter of 2002. This reduction was the result of a sharp drop in Canadian gas prices during the last half of June 2002. The end of June reference prices used in the Canadian ceiling calculation, expressed in Canadian dollars based on an exchange ratio of $0.6585, were a NYMEX price of C$40.79 per barrel of oil and an AECO price of C$2.17 per MMBtu. The cash market prices of natural gas increased during the month of July 2002 prior to Devon’s release of our second quarter results. However, this increase was not sufficient to offset the entire reduction calculated as of June 30.
Other Income (Expenses)
The details of the changes in other income (expenses) between 2002 and 2004 are shown in the table below.
A discussion of the significant other income (expense) items follows.
Interest Expense
2004 vs. 2003 The average debt balance outstanding decreased from $8.9 billion in 2003 to $8.5 billion in 2004 causing interest expense to decrease $21 million. The decrease in average debt outstanding was due to debt repayments during 2004. The average interest rate on outstanding debt was approximately 6.0% in both periods. However, a slightly higher rate in 2004 caused interest expense to increase $3 million.
Other items included in interest expense that are not related to the debt balance outstanding were $9 million lower in 2004. Of this decrease, $20 million related to the capitalization of interest. The increase in interest capitalized was primarily related to additional unproved properties acquired from the April 2003 Ocean merger and the nature of the properties acquired. The Ocean properties included significant deepwater Gulf and international exploratory properties and major development projects. The effect of the $20 million increase in capitalized interest was partially offset by $16 million of debt issuance costs expensed in 2004. The $16 million related to the early repayment of the outstanding balance under the $3 billion term loan credit facility in the second quarter of 2004.
2003 vs. 2002 The average debt balance outstanding increased from $8.3 billion in 2002 to $8.9 billion in 2003 causing interest expense to increase $32 million. The increase in average debt outstanding was attributable primarily to the debt assumed as a result of the April 2003 Ocean merger. The average interest rate on outstanding debt was 6.0% in both periods.
Other items included in interest expense that are not related to the debt balance outstanding were $63 million lower in 2003. Of this decrease, $46 million related to the capitalization of interest, $10 million related to lower net accretion and $8 million related to the loss on the early extinguishment of the 8.75% senior notes in 2002. The increase in interest capitalized was primarily related to additional unproved properties acquired from the April 2003 Ocean merger.
Effects of Changes in Foreign Currency Exchange Rates
Our Canadian subsidiary which has designated the Canadian dollar as its functional currency 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 while the notes are outstanding 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 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 $0.7738 at December 31, 2003 to $0.8308 at December 31, 2004 resulted in a $22 million gain. The increase in the Canadian-to-U.S. dollar exchange rate from $0.6331 at December 31, 2002 to $0.7738 at December 31, 2003 resulted in a $69 million gain. The increase in the Canadian-to-U.S. dollar exchange rate from $0.6279 at December 31, 2001 to $0.6331 at December 31, 2002 resulted in a $1 million gain.
Impairment of ChevronTexaco Corporation Common Stock in
In the fourth quarter of 2002, Devon recorded a $205 million other-than-temporary impairment of our investment in 14.2 million shares of ChevronTexaco common stock. We acquired these shares in the August 1999 acquisition of PennzEnergy Company. The shares are deposited with an exchange agent for possible exchange for $760 million of debentures that are exchangeable into the ChevronTexaco shares. The debentures, which mature in August 2008, were also assumed by Devon in the 1999 PennzEnergy acquisition.
At the closing date of the PennzEnergy acquisition, we initially recorded the ChevronTexaco common shares at their fair value, which was $47.69 per share, or an aggregate value of $677 million. Since then, as the ChevronTexaco shares have fluctuated in market value, the value of the shares on Devon’s balance sheet has been adjusted to the applicable market value. Through September 30, 2002, any decreases in the value of the ChevronTexaco common shares were determined by Devon to be temporary in nature. Therefore, the changes in value were recorded directly to stockholders’ equity and were not recorded in our results of operations through September 30, 2002.
The determination that a decline in value of the ChevronTexaco shares is temporary or other than temporary is subjective and influenced by many factors. Among these factors are the significance of the decline as a percentage of the original cost and the length of time the stock price has been below original cost. Other factors are the performance of the stock price in relation to the stock price of its competitors within the industry and the market in general, and whether the decline is attributable to specific adverse conditions affecting ChevronTexaco.
Beginning in July 2002, the market value of ChevronTexaco common stock began a significant decline. The price per share decreased from $44.25 at June 30, 2002, to $34.63 per share at September 30, 2002, and to $33.24 per share at December 31, 2002. The year-end price of $33.24 represented a 25% decline since June 30, 2002, and a 30% decline from the original valuation in August 1999. As a result of the decline in value during the fourth quarter of 2002, Devon determined that the decline was other than temporary, as that term is defined by accounting rules. Therefore, the $205 million cumulative decrease in
the value of the ChevronTexaco common shares from the initial acquisition in August 1999 to December 31, 2002, was recorded as a noncash charge to Devon’s results of operations in the fourth quarter of 2002. Net of the applicable tax benefit, the charge reduced our net earnings by $128 million.
The share price of ChevronTexaco common stock has increased to $43.19 at December 31, 2003 and $52.51 at December 31, 2004. As a result, the market value of Devon’s investment in ChevronTexaco common stock increased $273 million from December 31, 2002 to December 31, 2004. The changes in the value of the shares since December 31, 2002, net of applicable taxes, have been recorded directly to stockholders’ equity. However, depending on the future performance of ChevronTexaco’s common stock, Devon may be required to record additional noncash charges in future periods if the value of such stock declines, and we determine that such declines are other than temporary
Other Income
2004 vs. 2003 Other income increased $66 million in 2004. Other income increased $37 million due to gains resulting from sales of certain non-oil and gas properties in 2004. Interest and dividend income increased $12 million in 2004 due to an increase in cash and short-term investment balances.
Income Taxes
2004 vs. 2003 Devon’s 2004 effective financial tax rate attributable to continuing operations was an expense of 34% compared to an expense of 23% in 2003. Both the 2004 and 2003 rates benefited from Canadian statutory rate reductions. These rate reductions resulted in a $36 million and $218 million benefit being recorded in 2004 and 2003, respectively, related to the lower tax rates being applied to deferred tax liabilities outstanding as of the beginning of the year. Excluding the effects of the Canadian rate reductions in 2004 and 2003 and the reduction of carrying value of oil and gas properties in 2003, the effective financial tax expense rates were 35% and 33% in 2004 and 2003, respectively. The 2004 rate was equal to the statutory federal tax rate primarily due to the effect of state income taxes offset by the tax benefits of certain foreign deductions. The 2003 rate was lower than the statutory federal tax rate primarily due to the tax benefits of certain foreign deductions.
2003 vs. 2002 Devon’s 2003 effective financial tax rate attributable to continuing operations was an expense of 23% compared to a benefit of 144% in 2002. The 2003 rate benefited from a statutory rate reduction enacted by the Canadian government. Excluding the effects of the 2003 Canadian rate reduction, the impairment of ChevronTexaco stock in 2002 and the reduction of carrying value of oil and gas properties in 2003 and 2002, the effective financial tax expense rates were 33% and 23% in 2003 and 2002, respectively. These rates in both years were lower than the statutory federal tax rate primarily due to the tax benefits of certain foreign deductions.
Results of Discontinued Operations
On April 18, 2002, we sold our Indonesian operations to PetroChina Company Limited for total cash consideration of $250 million. On October 25, 2002, we sold our Argentine operations to Petroleo Brasileiro S.A. for total cash consideration of $90 million. On January 27, 2003, we sold our Egyptian operations to IPR Transoil Corporation for total cash consideration of $7 million.
As a result, we reclassified our Indonesian, Argentine and Egyptian activities as discontinued operations. This reclassification affects not only the 2002 presentation of financial results, but also the presentation of all prior periods’ results. Subsequent to the sale of our Egyptian and Indonesian operations, we acquired new Egyptian and Indonesian assets in the April 2003 Ocean merger. Amounts and activities related to these new Egyptian and Indonesian operations are included in Devon’s continuing operations in both 2003 and 2004.
Following are the components of the net results of discontinued operations for the year 2002.
Cumulative Effect of Change in Accounting Principle
Effective January 1, 2003, we adopted SFAS No. 143 and recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million.
In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction of SFAS No. 143 with the full cost method of accounting for oil and gas properties. Specifically, SAB No. 106 clarifies the manner in which the full cost ceiling test and DD&A should be calculated in accordance with the provisions of SFAS No. 143. We adopted SAB No. 106 in the fourth quarter of 2004. However, this adoption did not materially impact our full cost ceiling test calculation or DD&A for 2004.
Capital Resources and Liquidity
The following discussion of liquidity and capital resources should be read in conjunction with the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data”.
Sources and Uses of Cash
Cash Flows from Operating Activities
Net cash provided by operating activities (“operating cash flow”) continued to be a primary source of capital and liquidity in 2004. Operating cash flow in 2004 was $4.8 billion compared to $3.8 billion in 2003 and $1.8 billion in 2002. The increases in operating cash flow in 2004 and 2003 were primarily caused by the increases in revenues, partially offset by increased expenses, as discussed in the “Results of Operations” section of this report.
Cash Flows from Investing Activities
Net cash used in investing activities was $3.6 billion in 2004 compared to $2.8 billion in 2003 and $2.0 billion in 2002. The increases in cash used in investing activities were directly related to increased capital expenditures net of proceeds from the sale of property and equipment, as well as increases in short-term investment balances of $626 million and $341 million in 2004 and 2003, respectively.
Capital expenditures in 2004 were $3.1 billion. This total includes $3.0 billion for the acquisition, drilling or development of oil and gas properties. These amounts compare to capital expenditures of $2.6 billion in 2003 and $3.4 billion in 2002. The 2003 amount included $2.5 billion for the acquisition, drilling or development of oil and gas properties. The 2002 amount included $1.7 billion related to the January 2002 Mitchell merger and $1.6 billion for other acquisitions and the drilling or development of oil and gas properties.
The April 2003 Ocean merger did not affect 2003 capital expenditures because the consideration given was Devon common stock. This differs from the January 2002 Mitchell merger, in which the consideration given was both Devon common stock and cash. As a result, the Mitchell merger did have an impact on capital expenditures paid in cash.
Proceeds from sales of property and equipment were $95 million, $179 million and $1.4 billion in 2004, 2003 and 2002, respectively. The 2002 amount includes proceeds from the sales of certain non-core oil and gas properties which were used to pay down debt.
Cash Flows from Financing Activities
Net cash used in financing activities during 2004 was $1.0 billion compared to $414 million in 2003. The increase in cash used in financing activities from 2003 to 2004 was directly related to increased debt repayments net of borrowings. The increase was also related to increased common stock dividends and the repurchase of common stock, partially offset by an increase in proceeds from the issuance of common stock. Net cash provided by financing activities was $401 million in 2002, consisting primarily of net proceeds from borrowings of long-term debt.
During 2004, Devon retired $973 million of debt. This was primarily related to the $211 million 6.75% notes due February 15, 2004 and the $125 million 8.05% notes due June 15, 2004, and payment of the remaining $635 million outstanding on the $3 billion term loan credit facility. During 2003, principal payments on long-term debt, net of proceeds from borrowings of long-term debt, were $521 million. This net amount related to long-term debt assumed in the April 2003 Ocean merger.
During 2002, Devon had net borrowings of $410 million. These net borrowings were primarily related to the $2 billion borrowed under the $3 billion term loan credit facility to pay for the cash portion of the Mitchell merger. This was partially offset primarily by the repayment of $1.1 billion of this facility with proceeds from the 2002 property sales, the early retirement of the 8.75% notes due June 15, 2007 and certain Canadian notes, and the retirement of Devon’s outstanding borrowings under its commercial paper and revolving credit facilities.
Devon’s common stock dividends were $97 million, $39 million and $31 million in 2004, 2003 and 2002, respectively. We also paid $10 million of preferred stock dividends in 2004, 2003 and 2002. The increase in common stock dividends from 2003 to 2004 was primarily related to a 100% increase in the quarterly dividend rate and the increased number of shares outstanding. Effective with the first quarter 2004 dividend payment, Devon increased its quarterly dividend rate from $0.025 per share to $0.05 per share. The increase in shares outstanding was primarily related to the April 2003 Ocean merger.
In conjunction with the stock buyback program announced September 27, 2004, Devon repurchased 5 million shares at a total cost of $189 million during 2004.
Devon received $268 million, $155 million and $32 million from shares issued for employee stock options exercised during 2004, 2003 and 2002, respectively.
Liquidity
At December 31, 2004, Devon’s unrestricted cash and cash equivalents and short-term investments totaled $2.1 billion. During 2004, 2003 and 2002, such balances increased $846 million, $981 million and $109 million, respectively.
Historically, Devon’s primary source of capital and liquidity has been operating cash flow. Additionally, we maintain a revolving line of credit and a commercial paper program which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity securities and long-term debt. Over the next twelve months another major source of liquidity will be proceeds from the sales of oil and gas properties as announced September 27, 2004. After-tax sale proceeds from the divestiture program are expected to range between $1.0 billion and $1.5 billion. We expect the combination of these sources of capital will be more than adequate to fund future capital expenditures, the common stock buyback program, and other contractual commitments as discussed later in this section.
Operating Cash Flow
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 our control and are difficult to predict.
To mitigate some of the risk inherent in oil and natural gas prices, Devon has utilized price collars to set minimum and maximum prices on a portion of its production. Additionally, we have entered into various financial price swap contracts and fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. The table below provides the volumes associated with these various arrangements as of December 31, 2004.
In addition to the above quantities, we have fixed-price physical delivery contracts covering Canadian natural gas production for the years 2007 through 2011 ranging from 8 Bcf to 14 Bcf per year. Also, Devon has a fixed-price physical delivery contract covering 4 Bcf and 3 Bcf of International natural gas production in 2007 and 2008, respectively. From 2012 through 2016, we have Canadian natural gas volumes subject to fixed-price contracts, but the yearly volumes are less than 1 Bcf.
It is our policy to only enter into derivative contracts with investment grade rated counterparties deemed by management as competent and competitive market makers. Devon does not hold or issue derivative instruments for speculative trading purposes.
Credit Lines
Another source of liquidity is our $1.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes (i) a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility.
The Senior Credit Facility matures on April 8, 2009, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 8 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. Devon has obtained lender approval to extend the current maturity date of April 8, 2009 to April 8, 2010. This maturity date extension will be effective April 8, 2005 provided Devon has not experienced a “material adverse effect,” as defined in the Senior Credit Facility agreement, at that date.
Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.
As of December 31, 2004, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of December 31, 2004, net of $226 million of outstanding letters of credit, was approximately $1.3 billion.
The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon to maintain a ratio of total funded debt to total capitalization of no more than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in Devon’s consolidated financial statements. Per the agreement, total funded debt excludes the debentures that are exchangeable into shares of ChevronTexaco Corporation common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or goodwill impairments. As of December 31, 2004, Devon’s ratio as calculated pursuant to this covenant was 33.0%.
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse condition” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our Senior Credit Facility includes covenants that require Devon to report a condition or event having a material adverse effect on Devon, the obligation of the banks to fund the Senior Credit Facility is not conditioned on the absence of a material adverse effect.
We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $725 million. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a maturity of up to 365 days. We had no commercial paper debt outstanding at December 31, 2004.
Debt Ratings
Devon receives debt ratings from the major ratings agencies in the United States. In determining our debt rating, the agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Liquidity, asset quality, cost structure, reserve mix, and commodity pricing levels are also considered by the rating agencies.
Devon’s current debt ratings are BBB with a stable outlook by Standard & Poor’s, Baa2 with a stable outlook by Moody’s and BBB with a stable outlook by Fitch. There are no “rating triggers” in any of our contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Certain of Devon’s agreements related to its oil and natural gas hedges do contain provisions that could require us to provide cash collateral in situations where our liability under the hedge is above a certain dollar threshold and where our debt rating is below investment grade (BBB- or Baa3). However, Devon’s liability under these agreements would only exceed the threshold level in circumstances where the market prices for oil or natural gas were rising. It is unlikely that our debt rating would be subjected to downgrades to non-investment grade levels during such a period of rising oil and natural gas prices.
Devon’s cost of borrowing under our Senior Credit Facility is predicated on its corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior
Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs for the Senior Credit Facility from LIBOR plus 70 basis points to a new rate of LIBOR plus 87.5 basis points. A ratings downgrade could also adversely impact our ability to economically access future debt markets.
As of December 31, 2004, we are not aware of any potential ratings downgrades being contemplated by the rating agencies.
Capital Expenditures
In February 2005, Devon announced its 2005 capital expenditures budget. Our 2005 capital expenditures are expected to range from $3.0 billion to $3.5 billion, representing the largest planned use of capital resources for capital investment activities. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if oil and natural gas prices fluctuate from current estimates, we could choose to defer a portion of these planned 2005 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2005 to achieve the desired balance between sources and uses of liquidity. Based upon current oil and natural gas price expectations for 2005, we anticipate that our capital resources will be more than adequate to fund 2005 capital expenditures.
Common Stock Buyback Program
During 2004 Devon repurchased five million shares of its common stock, and we intend to repurchase up to 45 million additional shares in 2005 in conjunction with a stock buyback program announced in September 2004. The shares will be repurchased with operating cash flow and proceeds from the planned sales of oil and gas properties announced on September 27, 2004. The stock repurchase program may be discontinued at any time.
Contractual Obligations
A summary of Devon’s contractual obligations as of December 31, 2004, is provided in the following table.
Firm transportation agreements represent “ship or pay” arrangements whereby we have committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. We have entered into these agreements to aid the movement of our gas production to market. Devon has sufficient production to utilize the majority of these transportation services.
Devon has two offshore platform spars that are being used in the development of the Nansen and Boomvang fields in the Gulf of Mexico. The operating leases are for 20-year terms and contain various
options whereby we may purchase the lessors’ interests in the spars. We have guaranteed that the spars will have residual values at the end of the operating leases equal to at least 10% of the fair value of the spars at the inception of the leases. The total guaranteed value is $20 million in 2022. However, such amount may be reduced under the terms of the lease agreements.
We also have two floating, production, storage and offloading facilities (“FPSO”) that are being leased under operating lease arrangements. One FPSO is being used in the Panyu project offshore China. The other is being used in the Zafiro field offshore Equatorial Guinea. The China lease expires in September 2009 and the Equatorial Guinea lease expires in July 2009.
The above table does not include $226 million of letters of credit that have been issued by commercial banks on Devon’s behalf. These letters of credit, if funded, would become borrowings under our revolving credit facility. Most of these letters of credit have been granted by Devon’s financial institutions to support our international and Canadian drilling commitments. The $8.0 billion of long-term debt shown in the table excludes $1 million of net discounts and a $9 million fair value adjustment. Both of these items are included in the December 31, 2004, book balance of the debt.
Pension Funding and Obligations
Devon’s pension expense is recognized on an accrual basis over employees’ approximate service periods and is generally calculated independent of funding decisions or requirements. We recognized expense for our defined benefit pension plans of $26 million, $35 million and $16 million in 2004, 2003 and 2002, respectively. We estimate that our pension expense will approximate $26 million in 2005.
As compared to the “projected benefit obligation,” Devon’s qualified and nonqualified defined benefit plans were underfunded by $132 million and $137 million at December 31, 2004 and 2003, respectively. The decrease in the underfunded amount during 2004 was primarily caused by gains on investments and $70 million of contributions made to the plans by Devon. These were partially offset by increases in the benefit obligations. A detailed reconciliation of the 2004 activity is included in Note 13 to the accompanying consolidated financial statements. Of the $132 million underfunded status at the end of 2004, $109 million is attributable to various nonqualified defined benefit plans which have no plan assets. However, we have established certain trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2004, these trusts had investments with a market value of $60 million. The value of these trusts is included in noncurrent other assets in our accompanying consolidated balance sheets.
As compared to the “accumulated benefit obligation,” our qualified defined benefit plans were overfunded by $11 million at December 31, 2004. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. Our current intentions are to provide sufficient funding in future years to ensure the accumulated benefit obligation remains fully funded. The actual amount of contributions required during this period will depend on investment returns from the plan assets. Required contributions also depend upon changes in actuarial assumptions made during the same period, particularly the discount rate used to calculate the present value of the accumulated benefit obligation. For 2005, Devon expects its contributions to the plan to be less than $10 million.
The calculation of pension expense and pension liability requires the use of a number of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Devon believes that the two most critical assumptions affecting pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate.
We assumed that our plan assets would generate a long-term weighted average rate of return of 8.34% and 8.25% at December 31, 2004 and 2003, respectively. We developed these expected long-term rate of return assumptions by evaluating input from external consultants and economists as well as long-term inflation assumptions. The expected long-term rate of return on plan assets is based on a target allocation of investment types in such assets. The target investment allocation for Devon’s plan assets is 50%
U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between growth and value; 15% international equity securities, equally allocated between growth and value; and 20% debt securities.
We believe that its long-term asset allocation on average will approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance the investments to the targeted allocation when considered appropriate.
Pension expense increases as the expected rate of return on plan assets decreases. A decrease in our long-term rate of return assumption of 100 basis points (from 8.34% to 7.34%) would increase the expected 2005 pension expense by approximately $4 million.
Devon discounted its future pension obligations using a weighted average rate of 5.74% at December 31, 2004, compared to 6.23% at December 31, 2003. The discount rate is determined at the end of each year based on the rate at which obligations could be effectively settled. This rate is based on high-quality bond yields, after allowing for call and default risk. We consider high quality corporate bond yield indices, such as Moody’s Aa, when selecting the discount rate.
The pension liability and future pension expense both increase as the discount rate is reduced. Lowering the discount rate by 25 basis points (from 5.74% to 5.49%) would increase our pension liability at December 31, 2004, by approximately $18 million, and increase estimated 2005 pension expense by approximately $2 million.
At December 31, 2004, Devon had unrecognized actuarial losses of $155 million. These losses will be recognized as a component of pension expense in future years. We estimate that approximately $9 million and $8 million of the unrecognized actuarial losses will be included in pension expense in 2005 and 2006, respectively. The $9 million estimated to be recognized in 2005 is a component of the total estimated 2005 pension expense of $26 million referred to earlier in this discussion.
Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Devon’s defined benefit pension plans will impact future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.
Critical Accounting Policies and Estimates
Full Cost Ceiling Calculations
We follow the full cost method of accounting for our oil and gas properties. The full cost method subjects companies to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. If Devon’s capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense. The ceiling limitation is imposed separately for each country in which we have oil and gas properties.
The discounted present value of future net revenues for our proved oil, natural gas and NGL reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Certain of our reserve estimates are prepared by outside petroleum consultants, while other reserve estimates are prepared by Devon’s engineers. See Note 18 of the accompanying consolidated financial statements.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. In the past five years, annual revisions
to our reserve estimates, which have been both increases and decreases in individual years, have averaged approximately 2% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are held constant indefinitely. Therefore, the future net revenues associated with the estimated proved reserves are not based on Devon’s assessment of future prices or costs. Rather, they are based on such prices and costs in effect as of the end of each quarter when the ceiling calculation is performed. In calculating the ceiling, we adjust the end-of-period price by the effect of cash flow hedges in place. This adjustment requires little judgment as the end-of-period price is adjusted using the contract prices for our cash flow hedges.
The ceiling calculation also dictates that a 10% discount factor is to be used to calculate the present value of net cash flows.
Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical. On any particular day at the end of a quarter, prices can be either substantially higher or lower than Devon’s long-term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Derivative Financial Instruments
Devon enters into oil and gas derivative financial instruments to manage its exposure to oil and gas price volatility. We have also entered into interest rate swaps to manage our exposures to interest rate volatility. The interest rate swaps mitigate either the effects on interest expense for variable-rate debt instruments, or the debt fair values for fixed-rate debt. We are not involved in any speculative trading activities of derivatives. All derivatives requiring balance sheet recognition are recognized on the balance sheet at their fair value.
A substantial portion of our derivatives consists of contracts that hedge the price of future oil and natural gas production. These derivative contracts are cash flow hedges that qualify for hedge accounting treatment. Therefore, while fair values of such hedging instruments must be estimated as of the end of each reporting period, the changes in the fair values attributable to the effective portion of these hedging instruments are not included in our consolidated results of operations. Instead, the changes in fair value of the effective portion of these hedging instruments, net of tax, are recorded directly to stockholders’ equity until the hedged oil or natural gas quantities are produced. The ineffective portion of these hedging instruments is included in our consolidated results of operations.
To qualify for hedge accounting treatment, we designate our cash flow hedge instruments as such on the date the derivative contract is entered into or the date of a business combination which includes cash flow hedge instruments. Additionally, we document all relationships between hedging instruments and hedged items, as well as our risk-management objective and strategy for undertaking various hedge transactions. Devon also assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. If we fail to meet the requirements for using hedge accounting treatment, the changes in fair value of these hedging instruments would not be recorded directly to equity but in the consolidated results of operations.
The estimates of the fair values of Devon’s commodity derivative contracts require substantial judgment. For these contracts, we obtain forward price and volatility data for all major oil and gas trading points in North America from independent third parties. These forward prices are compared to the price parameters contained in the hedge agreements. The resulting estimated future cash inflows or outflows over the lives of the hedge contracts are discounted using LIBOR and money market futures rates for the first year and money market futures and swap rates thereafter. In addition, we estimate the option value of price floors and price caps using an option pricing model. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices, regional price differentials and interest rates. Fair values of Devon’s other derivative contracts require less judgment to estimate and are primarily based on quotes from independent third parties such as counterparties or brokers.
Quarterly changes in estimates of fair value have only a minimal impact on our liquidity, capital resources or results of operations, as long as the derivative contracts qualify for treatment as a hedge. However, settlements of derivative contracts do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative contracts, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding the effects that changes in market prices will have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Devon’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how Devon views and manages its ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. and Canadian natural gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for several years.
Devon periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through various financial transactions which hedge the future prices received. These transactions include financial price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty, and costless price collars that set a floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage Devon’s exposure to oil and gas price fluctuations.
Devon’s total hedged positions on future production as of December 31, 2004 are set forth in the following tables.
Price Swaps
Through various price swaps, we have fixed the price we will receive on a portion of our oil and natural gas production in 2005. The following tables include information on this fixed-price production by area. Where necessary, the oil and gas prices related to these swaps have been adjusted for certain transportation costs that are netted against the price recorded by Devon, and the gas price has also been adjusted for the Btu content of the production that has been hedged.
Oil Production
Gas Production
Costless Price Collars
We have also entered into costless price collars that set a floor and ceiling price for a portion of our 2005 oil production that is otherwise subject to floating prices. The floor and ceiling prices related to
domestic and Canadian oil production are based on the NYMEX price. The floor and ceiling prices related to international oil production are based on the Brent price. If the NYMEX or Brent price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. As long as Devon meets the ongoing requirements of hedge accounting for its derivatives, any such settlements will either increase or decrease Devon’s oil revenues for the period. Because our oil volumes are often sold at prices that differ from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus heavy or sour crude) and transportation costs from different geographic areas, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
We have also entered into costless price collars that set a floor and ceiling price for a portion of our 2005 natural gas production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
To simplify presentation, our costless collars as of December 31, 2004 have been aggregated in the following tables according to similar floor prices and similar ceiling prices. The floor and ceiling prices shown are weighted averages of the various collars in each aggregated group.
The international oil prices shown in the following table have been adjusted to a NYMEX-based price, using our estimates of 2005 differentials between NYMEX and the Brent price upon which the collars are based.
The natural gas prices shown in the following table have been adjusted to a NYMEX-based price, using our estimates of future differentials between NYMEX and the specific regional indices upon which the collars are based. The floor and ceiling prices related to the collars are based on various regional first-of-the-month price indices as published monthly by Inside FERC.
Oil Production
Gas Production
Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of its commodity hedging instruments. At
December 31, 2004 a 10% increase in the underlying commodities’ prices would have increased the net liabilities recorded for our commodity hedging instruments by $115 million.
Fixed-Price Physical Delivery Contracts
In addition to the commodity hedging instruments described above, Devon also manages its exposure to oil and gas price risks by periodically entering into fixed-price contracts.
We have 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 fixed-price contracts, but the yearly volumes are less than 1 Bcf.
We also have fixed-price physical delivery contracts for the years 2005 through 2008 covering International natural gas production of 4 Bcf per year, except in 2008 when the volume drops to 3 Bcf.
Interest Rate Risk
At December 31, 2004, Devon had debt outstanding of $8.0 billion. Of this amount, $6.0 billion, or 75%, bears interest at fixed rates averaging 7.0%. Devon also has a floating-to-fixed interest rate swap in which we will record a fixed rate of 6.4% on a notional amount of $104 million in 2005 and 2006 and 6.3% on a notional amount of $32 million in 2007.
The remaining $1.8 billion of debt outstanding bears interest at floating rates. Included in the floating-rate debt is fixed-rate debt which has been converted to floating-rate debt through interest rate swaps. The terms of Devon’s Senior Credit Facility allow interest rates to be fixed at our option for periods of between seven to 180 days. As of December 31, 2004, there were no borrowings outstanding under the Senior Credit Facility. Following is a table summarizing the fixed-to-floating interest rate swaps with the related debt instrument and notional amounts.
(1)
Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8308 as of December 31, 2004.
Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in interest rates may have on the fair value of its interest rate swap instruments. At December 31, 2004, a 10% increase in the underlying interest rates would have decreased the fair value of Devon’s interest rate swaps by $28 million.
The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.
Foreign Currency Risk
Devon’s net assets, net earnings and cash flows from its Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.
Our Canadian subsidiary, Devon Canada, has $400 million of fixed-rate long-term debt that is denominated in U.S. dollars. Changes in the currency conversion rate between the Canadian and U.S. dollars between the beginning and end of a reporting period increase or decrease the expected amount of Canadian dollars required to repay the notes. The amount of such increase or decrease is required to be included in determining net earnings for the period in which the exchange rate changes. A 10% decrease in the Canadian-to-U.S. dollar exchange rate would cause us to record a charge of approximately $40 million in 2005. The $400 million becomes due in March 2011. Until then, the gains or losses caused by the exchange rate fluctuations have no effect on cash flow.
Item 8.
Item 8.
Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (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 Devon Energy Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
As described in Note 1 to the consolidated financial statements, as of January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Devon Energy Corporation’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 4, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Oklahoma City, Oklahoma
March 4, 2005
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS - (Continued)
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (LOSS)
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Accounting policies used by Devon Energy Corporation and subsidiaries (“Devon”) reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are briefly discussed below.
Nature of Business and Principles of Consolidation
Devon is engaged primarily in oil and gas exploration, development and production, and the acquisition of properties. Such activities domestically are concentrated in four geographic areas:
•
the Permian Basin within Texas and New Mexico;
•
the Rocky Mountains area of the United States stretching from the Canadian Border into Northern New Mexico;
•
the Mid-Continent area of the central and southern United States; and
•
the Gulf Coast, which includes properties located primarily in the onshore South Texas and South Louisiana areas and offshore in the Gulf of Mexico.
Devon’s Canadian activities are located primarily in the Western Canadian Sedimentary Basin, and Devon’s international activities - outside of North America - are located primarily in Azerbaijan, China, Egypt, and areas in West Africa, including Equatorial Guinea, Gabon and Cote d’Ivoire.
Devon also has marketing and midstream operations which are responsible for marketing natural gas, crude oil and NGLs, and constructing and operating pipelines, storage and treating facilities and gas processing plants. These services are performed for Devon as well as for unrelated third parties.
The accounts of Devon’s wholly owned subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include estimates of proved reserves and related present value estimates of future net revenue, the carrying value of oil and gas properties, goodwill impairment assessment, asset retirement obligations, income taxes, valuation of derivative instruments, obligations related to employee benefits and legal and environmental risks and exposures. Actual amounts could differ from those estimates.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and which are not related to production, general corporate overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties under current evaluation and major development projects of oil and gas properties are also capitalized.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment quarterly. Significant unproved properties are assessed individually. Costs of insignificant unproved properties are transferred to amortizable costs over average holding periods ranging from three years for onshore properties to seven years for offshore properties.
Net capitalized costs are limited to the estimated future net revenues, discounted at 10% per annum, from proved oil, natural gas and NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement obligations, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves in a particular country. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.
Depreciation of midstream pipelines are provided on a units-of-production basis. Depreciation and amortization of other property and equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based on estimated useful lives from three to 39 years.
Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards (“SFAS”) 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. The initial measurement of the asset retirement obligation is to record a separate liability at its fair value with an offsetting asset retirement cost recorded as an increase to the related property and equipment on the consolidated balance sheet. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.
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.
Assuming the provisions of SFAS No. 143 had been adopted as of January 1, 2002, Devon’s 2002 net earnings would have been $5 million less than the reported 2002 net earnings. This would have also resulted in a $0.02 and $0.01 reduction to 2002 basic and diluted net earnings applicable to common stockholders, respectively.
In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction of SFAS No. 143 with the full cost method of accounting for oil and gas properties. Specifically, SAB No. 106 clarifies the manner in which the full cost ceiling test and depletion of oil and gas properties should be calculated in accordance with the provisions of
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
SFAS No. 143. Devon adopted SAB No. 106 prospectively in the fourth quarter of 2004. However, this adoption did not materially impact the full cost ceiling test calculation or depletion for 2004.
Short-Term Investments and Other Marketable Securities
Devon reports its short-term investments and other marketable securities at fair value, except for debt securities in which management has the ability and intent to hold until maturity. At December 31, 2004 and 2003, Devon’s short-term investments consisted of $967 million and $341 million, respectively, of auction rate securities classified as available for sale. Although Devon’s auction rate securities have contractual maturities of more than 10 years, the underlying interest rates on such securities reset at intervals ranging from 7 to 49 days. Therefore, these auction rate securities are priced and subsequently trade as short-term investments because of the interest rate reset feature. As a result, Devon has classified its auction rate securities as short-term investments in the accompanying consolidated balance sheet. The 2003 balance of such securities was previously classified as cash equivalents due to the liquidity and pricing reset feature. In 2004, these securities were reclassified as short-term investments to conform to current year presentation. There was no impact on net earnings or cash flow from operations as a result of the reclassification.
Devon’s only other significant investment security is its investment in approximately 14.2 million shares of ChevronTexaco Corporation (“ChevronTexaco”) common stock which is reported at fair value. Except for unrealized losses that are determined to be “other than temporary”, the tax effected unrealized gain or loss on the investment in ChevronTexaco common stock is recognized in other comprehensive income (loss) and reported as a separate component of stockholders’ equity.
Goodwill
Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired and is tested for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. Devon performed annual impairment tests of goodwill in the fourth quarters of 2004, 2003 and 2002. Based on these assessments, no impairment of goodwill was required.
The table below provides a summary of Devon’s goodwill, by assigned reporting unit, as of December 31, 2004 and 2003:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenue Recognition and Gas Balancing
Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline or truck or a tanker lifting has occurred. Cash received relating to future production is deferred and recognized when all revenue recognition criteria are met.
Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through production. If an imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a variety of arrangements. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has taken less than its share of production unless all revenue recognition criteria are met.
Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, when delivery or performance has occurred and title has transferred, and if collectibility of the revenue is probable. Revenues and expenses attributable to Devon’s NGL purchase and processing contracts are reported on a gross basis since Devon takes title to the products and has risks and rewards of ownership. The gas purchased under these contracts is processed in Devon-owned plants.
Major Purchasers
No purchaser accounted for over 10% of revenues in 2004, 2003 and 2002.
Derivative Instruments
Devon enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. Devon has also entered into interest rate swaps to manage its exposure to interest rate volatility. The interest rate swaps mitigate either the effects of interest rate fluctuations on interest expense for variable-rate debt instruments, or the debt fair values for fixed-rate debt.
All derivatives are recognized as fair value of financial instruments on the consolidated balance sheets at their fair value. A substantial portion of Devon’s derivatives consists of contracts that hedge the price of future oil and natural gas production. These derivative contracts are cash flow hedges that qualify for hedge accounting treatment. Therefore, while fair values of such hedging instruments must be estimated as of the end of each reporting period, the changes in the fair values attributable to the effective portion of these hedging instruments are not included in Devon’s consolidated results of operations. Instead, the changes in fair value of the effective portion of these hedging instruments, net of tax, are recorded directly to accumulated other comprehensive income, a component of stockholders’ equity, until the hedged oil or natural gas quantities are produced. The ineffective portion of these hedging instruments is included in consolidated results of operations.
To qualify for hedge accounting treatment, Devon designates its cash flow hedge instruments as such on the date the derivative contract is entered into or the date of a business combination which includes cash flow hedge instruments. Additionally, Devon documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. Devon also assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. If Devon fails to meet the requirements for using hedge accounting treatment or the hedged
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
transaction is no longer likely to occur, the changes in fair value of these hedging instruments would not be recorded directly to equity but in the consolidated results of operations. During 2004, 2003 and 2002, there were no gains or losses reclassified into earnings as a result of the discontinuance of hedge accounting treatment for any of Devon’s derivatives.
By using derivative instruments to hedge exposures to changes in commodity prices and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with counterparties that Devon believes are minimal credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers.
Market risk is the change in the value of a derivative instrument that results from a change in commodity prices or interest rates. The market risk associated with commodity price and interest rate contracts is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The oil and gas reference prices upon which the commodity hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
Devon does not hold or issue derivative instruments for speculative trading purposes. Devon’s commodity costless price collars and price swaps have been designated as cash flow hedges. Changes in the fair value of these derivatives are reported on the balance sheet in accumulated other comprehensive income. These amounts are reclassified to oil and gas sales when the forecasted transaction takes place.
During 2004, 2003 and 2002, Devon recorded in its statements of operations a loss of $62 million, a gain of $1 million and a gain of $28 million, respectively, for the change in the 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.
As of December 31, 2004, $395 million of net deferred losses on derivative instruments accumulated in accumulated other comprehensive income are expected to be reclassified to oil and gas sales during the next 12 months assuming no change in the forward commodity prices from the December 31, 2004 forward prices. Transactions and events expected to occur over the next 12 months that will necessitate reclassifying these derivatives’ losses to earnings are primarily the production and sale of oil and natural gas which includes the production hedged under the various derivative instruments. Presently, the maximum term over which Devon has hedged exposures to the variability of cash flows for commodity price risk under its various derivative instruments is 12 months.
Common Stock
On September 27, 2004, Devon declared a two-for-one stock split, effected in the form of a stock dividend, to stockholders of record on October 29, 2004. Common stock shares and per share amounts for prior years have been restated to reflect this two-for-one stock split.
Stock Options
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 is 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, (“SFAS No. 123”) established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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 2004, 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.
The weighted average fair values of stock options granted during 2004, 2003 and 2002 were $10.32, $8.14 and $7.63, respectively. The fair value of each option grant was estimated for disclosure purposes on the date of grant using the Black-Scholes Option Pricing Model with the following assumptions for 2004, 2003 and 2002, respectively: risk-free interest rates of 3.2%, 2.8% and 3.2%; dividend yields of 0.5%, 0.4% and 0.4%; expected lives of four, four and five years; and volatility of the price of the underlying common stock of 32.2%, 37.9% and 41.8%.
Income Taxes
Devon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. For 2004, undistributed earnings of foreign subsidiaries were determined to be permanently reinvested. Therefore, no U.S. deferred income taxes were provided on such amounts at December 31, 2004.
In October 2004, Congress enacted new tax legislation allowing qualifying corporations to repatriate cash from foreign operations at a reduced income tax rate. In addition, this tax legislation creates a new U.S. tax deduction which will be phased in starting in 2005 for companies with domestic production
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
activities, including oil and gas extraction. In the first quarter of 2005, Devon’s board of directors approved the repatriation of $500 million of earnings from Canadian operations which will be taxed at the reduced income tax rate. As a result, Devon will recognize in the first quarter of 2005 approximately $30 million of additional current income tax expense (which would have been the same approximate amount recognized in 2004 if Devon had finalized its repatriation plans prior to 2005).
General and Administrative Expenses
General and administrative expenses are reported net of amounts reimbursed by working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Net Earnings Per Common Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if Devon’s dilutive outstanding stock options were exercised (calculated using the treasury stock method), if the preferred stock of a subsidiary were converted to common stock and if Devon’s zero coupon convertible senior debentures were converted to common stock.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for 2004, 2003 and 2002.
The senior convertible debentures included in the 2004 and 2003 dilution calculations were not included in the 2002 dilution calculation because the effect of 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 year. The following information relates to these options.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The excluded options for 2004 expire between January 9, 2007 and December 8, 2012.
Foreign Currency Translation Adjustments
Devon’s Canadian subsidiaries use the Canadian dollar as their functional currency. Therefore, the assets and liabilities of Devon’s Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates, while income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. Devon’s International subsidiaries use the U.S. dollar as their functional currency.
Statements of Cash Flows
For purposes of the consolidated statements of cash flows, Devon considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Environmental expenditures are expensed or capitalized in accordance with accounting principles generally accepted in the United States of America. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Reference is made to Note 14 for a discussion of amounts recorded for these liabilities.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current year presentation.
Impact of Recently Issued Accounting Standards Not Yet Adopted
In December 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123(R), “Share-Based Payment”, (“SFAS No. 123(R)”) which is a revision of SFAS No. 123 and supersedes APB Opinion No. 25 regarding stock-based employee compensation plans. APB Opinion No. 25 requires recognition of compensation expense only if the current market price of the underlying stock exceeded the stock option exercise price on the date of grant. Additionally, SFAS No. 123 established fair value-based accounting for stock-based employee compensation plans but allowed pro forma disclosure as an alternative to financial statement recognition. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable vesting period. Also, pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. Devon will adopt the provisions of SFAS No. 123(R) in the third quarter of 2005 and anticipates adopting SFAS No. 123(R) using the modified prospective method. Under this method, Devon will recognize compensation expense for all stock-based awards granted or modified on or after July 1, 2005, as well as any previously granted awards that are not fully vested as of July 1, 2005. Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123. Devon is currently assessing the impact of adopting SFAS No. 123(R) on consolidated results of operations. However, Devon does not expect such impact to be material upon adoption in the third quarter of 2005.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2.
Business Combinations and Pro Forma Information
Ocean Energy, Inc.
On April 25, 2003, Devon completed its merger with Ocean Energy, Inc. (“Ocean”). In the transaction, Devon issued 0.828 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 148 million shares). Also, Devon assumed approximately $1.8 billion of debt (current and long-term) from Ocean.
Devon acquired Ocean primarily for the significant production, development projects and exploration prospects in both the deepwater Gulf of Mexico and internationally, and the additional producing assets onshore in the United States and in the shallower shelf regions of the Gulf of Mexico.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The calculation of the purchase price and the allocation to assets and liabilities are shown below.
Pro Forma Information
Set forth in the following table is certain unaudited pro forma financial information for the year ended December 31, 2003. The information has been prepared assuming the Ocean merger and Devon’s January 24, 2002 merger with Mitchell Energy & Development Corp. 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. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
3.
Comprehensive Income or Loss
Devon’s comprehensive income or loss information is included in the accompanying consolidated statements of stockholders’ equity and comprehensive income (loss). A summary of accumulated other comprehensive income or loss as of December 31, 2004, 2003 and 2002, and changes during each of the years then ended, is presented in the following table.
The 2002 activity for unrealized gain (loss) on marketable securities includes unrealized losses of $164 million ($103 million net of taxes), offset by the recognition of a $205 million loss ($128 million net of taxes) in the statement of operations during 2002. The recognized loss was due to the impairment of the ChevronTexaco common stock owned by Devon.
4.
Supplemental Cash Flow Information
Cash payments (refunds) for interest and income taxes in 2004, 2003 and 2002 are presented below:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The 2003 Ocean merger and 2002 Mitchell merger involved non-cash consideration as presented below:
5.
Accounts Receivable
The components of accounts receivable included the following:
6.
Property and Equipment and Asset Retirement Obligations
Property and equipment included the following:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The costs not subject to amortization relate to unproved properties which are excluded from amortized capital costs until it is determined whether or not proved reserves can be assigned to such properties. The excluded properties are assessed for impairment at least annually. Subject to industry conditions, evaluation of most of these properties, and the inclusion of their costs in the amortized capital costs is expected to be completed within five years.
The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2004:
As described in Note 1, effective January 1, 2003, Devon adopted SFAS No. 143 and began recording asset retirement obligations for estimated property and equipment dismantlement, abandonment and restoration costs when a legal obligation is incurred. In accordance with SFAS No. 143, oil and gas properties subject to amortization and other property and equipment listed above include asset retirement costs associated with these asset retirement obligations. Following is a reconciliation of the asset retirement obligation for the years ended December 31, 2004 and 2003.
7.
Investment in ChevronTexaco Corporation Common Stock
In the fourth quarter of 2002, Devon recorded a $205 million other-than-temporary impairment of its investment in 14.2 million shares of ChevronTexaco common stock. Devon acquired these shares in its August 1999 acquisition of PennzEnergy Company. The shares are deposited with an exchange agent for possible exchange for $760 million of debentures that are exchangeable into the ChevronTexaco shares.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The debentures, which mature in August 2008, were also assumed by Devon in the 1999 PennzEnergy acquisition.
At the closing date of the PennzEnergy acquisition, Devon initially recorded the ChevronTexaco common shares at their fair value, which was $47.69 per share, or an aggregate value of $677 million. Since then, as the ChevronTexaco shares have fluctuated in market value, the value of the shares on Devon’s balance sheet has been adjusted to the applicable market value. Through September 30, 2002, any decreases in the value of the ChevronTexaco common shares were determined by Devon to be temporary in nature. Therefore, the changes in value were recorded directly to stockholders’ equity and were not recorded in Devon’s results of operations through September 30, 2002.
The determination that a decline in value of the ChevronTexaco shares is temporary or other than temporary is subjective and influenced by many factors. Among these factors are the significance of the decline as a percentage of the original cost, the length of time the stock price has been below original cost, the performance of the stock price in relation to the stock price of its competitors within the industry and the market in general, and whether the decline is attributable to specific adverse conditions affecting ChevronTexaco.
Beginning in July 2002, the market value of ChevronTexaco common stock began a significant decline. The price per share decreased from $44.25 at June 30, 2002, to $34.63 per share at September 30, 2002, and to $33.24 per share at December 31, 2002. The 2002 year-end price of $33.24 represented a 25% decline since June 30, 2002, and a 30% decline from the original valuation in August 1999. As a result of the decline in value during the fourth quarter of 2002, Devon determined that the decline was other than temporary, as that term is defined by accounting rules. Therefore, the $205 million cumulative decrease in the value of the ChevronTexaco common shares from the initial acquisition in August 1999 to December 31, 2002, was recorded as a noncash charge to Devon’s results of operations in the fourth quarter of 2002. Net of the applicable tax benefit, the charge reduced net earnings by $128 million.
The share price of ChevronTexaco common stock has increased to $43.19 at December 31, 2003 and $52.51 at December 31, 2004. As a result, the market value of Devon’s investment in ChevronTexaco common stock increased $273 million from December 31, 2002 to December 31, 2004. The changes in the value of the shares since December 31, 2002, net of applicable taxes, have been recorded directly to accumulated other comprehensive income in stockholders’ equity. However, depending on the future performance of ChevronTexaco’s common stock, Devon may be required to record additional noncash charges in future periods if the value of such stock declines, and Devon determines that such declines are other than temporary.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
8.
Long-Term Debt and Related Expenses
A summary of Devon’s long-term debt is as follows:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Maturities of long-term debt as of December 31, 2004, excluding the $1 million of net discounts and the $9 million fair value adjustment, are as follows (in millions):
Credit Facilities with Banks
Devon has a $1.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit Facility includes (i) a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility.
The Senior Credit Facility matures on April 8, 2009, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 8 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. Devon has obtained lender approval to extend the current maturity date of April 8, 2009 to April 8, 2010. This maturity date extension will be effective on April 8, 2005 provided Devon has not experienced a “material adverse effect,” as defined in the Senior Credit Facility agreement, at that date.
Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.
The agreement governing the Senior Credit Facility contains certain covenants and restrictions, including a maximum allowed debt-to-capitalization ratio of 65% as defined in the agreement. At December 31, 2004, Devon was in compliance with such covenants and restrictions. Devon’s debt-to-capitalization ratio at December 31, 2004, as calculated pursuant to the terms of the agreement, was 33.0%.
As of December 31, 2004, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit Facility as of December 31, 2004, net of $226 million of outstanding letters of credit, was approximately $1.3 billion.
Commercial Paper
Devon also has a commercial paper program under which it may borrow up to $725 million. Borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. The commercial paper borrowings may have terms of up to 365 days and bear interest at rates agreed to at the time of the borrowing. The interest rate is based on a standard index such as the Federal Funds Rate, London Interbank Offered Rate (LIBOR), or the money market rate as found on the commercial paper market. As of December 31, 2004 and 2003, Devon had no commercial paper debt outstanding.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Exchangeable Debentures
The exchangeable debentures consist of $444 million of 4.90% debentures and $316 million of 4.95% debentures. The exchangeable debentures were issued on August 3, 1998 and mature August 15, 2008. The exchangeable debentures were callable beginning August 15, 2000, initially at 104.0% of principal and at prices declining to 100.5% of principal on or after August 15, 2007. At December 31, 2004, the call price was 102.0% of principal. The exchangeable debentures are exchangeable at the option of the holders at any time prior to maturity, unless previously redeemed, for shares of ChevronTexaco common stock. In lieu of delivering ChevronTexaco common stock to an exchanging debenture holder, Devon may, at its option, pay to such holder an amount of cash equal to the market value of the ChevronTexaco common stock. At maturity, holders who have not exercised their exchange rights will receive an amount in cash equal to the principal amount of the debentures.
As of December 31, 2004, Devon beneficially owned approximately 14.2 million shares of ChevronTexaco common stock. These shares have been deposited with an exchange agent for possible exchange for the exchangeable debentures. Each $1,000 principal amount of the exchangeable debentures is exchangeable into 18.6566 shares of ChevronTexaco common stock, an exchange rate equivalent to $53.60 per share of ChevronTexaco stock.
The exchangeable debentures were assumed as part of the PennzEnergy merger. The fair values of the exchangeable debentures were determined as of August 17, 1999, based on market quotations. In accordance with derivative accounting standards, the total fair value of the debentures has been allocated between the interest-bearing debt and the option to exchange ChevronTexaco common stock that is embedded in the debentures. Accordingly, a discount was recorded on the debentures and is being accreted using the effective interest method which raised the effective interest rate on the debentures to 7.76%.
Zero Coupon Convertible Debentures
In June 2000, Devon privately sold zero coupon convertible senior debentures. The debentures were sold at a price of $464.13 per debenture with a yield to maturity of 3.875% per annum. Each of the 760,000 debentures is convertible into 11.5186 shares of Devon common stock. Devon may call the debentures at any time after five years, and a debenture holder has the right to require Devon to repurchase the debentures after five, 10 and 15 years, at the issue price plus accrued original issue discount and interest. The first put date is June 26, 2005, at an accreted value of $427 million. Therefore, Devon has classified these debentures as current liabilities in the December 31, 2004 consolidated balance sheet. Devon has the right to satisfy its obligation by paying cash or issuing shares of Devon common stock with a value equal to its obligation. Devon’s proceeds were approximately $346 million, net of debt issuance costs of approximately $7 million. Devon used the proceeds from the sale of these debentures to pay down other domestic long-term debt.
Other Debentures and Notes
Following are descriptions of the various other debentures and notes outstanding at December 31, 2004, as listed in the table presented at the beginning of this note.
Ocean Debt
In connection with the Ocean merger, Devon assumed $1.8 billion of debt. The table below summarizes the debt assumed which remains outstanding, the fair value of the debt at April 25, 2003, and the effective interest rate of the debt assumed after determining the fair values of the respective notes
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
using April 25, 2003, market interest rates. The premiums and discounts are being amortized or accreted using the effective interest method. All of the notes are general unsecured obligations of Devon.
Anderson Debt
In connection with the Anderson acquisition, Devon assumed $702 million of senior notes. The table below summarizes the debt assumed which remains outstanding, the fair value of the debt at October 15, 2001, and the effective interest rate of the debt assumed after determining the fair values of the respective notes using October 15, 2001, market interest rates. The premiums and discounts are being amortized or accreted using the effective interest method. All of the notes are general unsecured obligations of Devon.
2.75% Notes due August 1, 2006
On August 4, 2003, Devon issued these notes which are unsecured and unsubordinated obligations of Devon. The proceeds from the issuance of these debt securities, net of discounts and issuance costs, of $498 million were used to repay amounts outstanding under the $3 billion term loan credit facility.
10.25% Debentures due November 1, 2005 and 10.125% Debentures due November 15, 2009
These debentures were assumed as part of the PennzEnergy acquisition. The fair values of the respective debentures were determined using August 17, 1999, market interest rates. As a result, premiums were recorded on these debentures which lowered their effective interest rates to 8.3% and 8.9% on the $236 million of 10.25% debentures and $177 million of 10.125% debentures, respectively. The premiums are being amortized using the effective interest method.
6.875% Notes due September 30, 2011 and 7.875% Debentures due September 30, 2031
On October 3, 2001, Devon, through Devon Financing Corporation, U.L.C. (“Devon Financing”), sold these notes and debentures which are unsecured and unsubordinated obligations of Devon Financing. Devon has fully and unconditionally guaranteed on an unsecured and unsubordinated basis the obligations of Devon Financing under the debt securities. The proceeds from the issuance of these debt securities were used to fund a portion of the Anderson acquisition. The $3 billion of debt securities were structured in a manner that results in an expected weighted average after-tax borrowing rate of approximately 1.65%.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7.95% Notes due April 15, 2032
On March 25, 2002, Devon sold these notes which are unsecured and unsubordinated obligations of Devon. The net proceeds received, after discounts and issuance costs, were $986 million and were partially used to pay down $820 million on Devon’s $3 billion term loan credit facility. The remaining $166 million of net proceeds was used in June 2002 to partially fund the early extinguishment of $175 million of 8.75% senior subordinated notes due June 15, 2007. The notes were redeemed at 104.375% of principal, or approximately $183 million.
Interest Expense
Following are the components of interest expense for the years 2004, 2003 and 2002:
Effects of Changes in Foreign Currency Exchange Rates
The $400 million of 6.75% fixed-rate senior notes referred to in the first table of this note are payable by a Canadian subsidiary of Devon. However, the notes 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 assumed as part of an acquisition to the date of repayment increase or decrease the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent of the debt and certain cash and other working capital amounts of Devon’s Canadian subsidiary which are also denominated in U.S. dollars are required to be included in determining net earnings for the period in which the exchange rate changed. As a result of changes in the rate of conversion of Canadian dollars to U.S. dollars, $22 million, $69 million and $1 million was recorded as a reduction of expense in 2004, 2003 and 2002, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
9.
Income Taxes
At December 31, 2004, Devon had the following net operating loss carryforwards which are available to reduce future taxable income in the jurisdiction where the net operating loss was incurred. These carryforwards will result in a future tax reduction based upon the future tax rate applicable to the taxable income that is ultimately offset by the net operating loss carryforward.
Additionally, at December 31, 2004, Devon had $29 million of U.S. minimum tax credit carryforwards which have no expiration and are available to reduce future income taxes. The net operating loss and minimum tax credit carryforward amounts have been recognized for financial purposes to reduce the deferred tax liability at December 31, 2004.
The earnings (loss) before income taxes and the components of income tax expense (benefit) for the years 2004, 2003 and 2002 were as follows:
The taxes on the results of discontinued operations presented in the accompanying statements of operations were all related to foreign operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle as a result of the following:
During 2004 and 2003, total income tax expense was reduced by the effects of Canadian statutory rate reductions. As presented in the table above, these rate reductions resulted in a $36 million and $218 million benefit being recorded in 2004 and 2003, respectively, related to the lower tax rates being applied to deferred tax liabilities outstanding as of the beginning of the year.
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2004 and 2003 are presented below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As shown in the above table, Devon has recognized $956 million of deferred tax assets as of December 31, 2004. Such amount consists of $336 million of various carryforwards available to offset future income taxes. The carryforwards include federal net operating loss carryforwards, the majority of which do not begin to expire until 2020, state net operating loss carryforwards which expire primarily between 2005 and 2022, Canadian net operating loss carryforwards which expire primarily between 2006 and 2014, and Azerbaijani net operating loss carryforwards and U.S. minimum tax credit carryforwards which have no expiration. The tax benefits of carryforwards are 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,” a valuation allowance is provided to reduce the recorded tax benefits from such assets.
Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2005 and 2009. 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 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, management believes that Devon’s future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration.
10.
Preferred Stock of a Subsidiary
At December 31, 2003, a subsidiary of Devon created in the Ocean merger had 38,000 shares of convertible preferred stock outstanding. In January 2004, these shares of convertible preferred stock were canceled and converted to 2,197,160 shares of Devon common stock pursuant to an automatic conversion feature of the preferred stock. The automatic conversion feature was triggered when the closing price of Devon common stock equaled or exceeded the forced conversion price of $26.20 for 20 consecutive trading days.
11.
Stockholders’ Equity
The authorized capital stock of Devon consists of 800 million shares of common stock, par value $0.10 per share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
There were 32 million exchangeable shares issued on December 10, 1998, in connection with the Northstar Energy Corporation combination. These shares were essentially equivalent to Devon common stock and were exchangeable at any time, on a one-for-one basis, for common shares of Devon at the holder’s option. The last remaining exchangeable shares outstanding were exchanged for Devon common stock on August 27, 2004.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49% cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative preferred stock, Series A. Dividends on the preferred stock are cumulative from the date of original issue and are payable quarterly, in cash, when declared by the Board of Directors. The preferred stock is redeemable at the option of Devon at any time on or after June 2, 2008, in whole or in part, at a redemption price of $100 per share, plus accrued and unpaid dividends to the redemption date.
Devon’s Board of Directors has designated a certain number of shares of the preferred stock as Series A Junior Participating Preferred Stock (the “Series A Junior Preferred Stock”) in connection with the adoption of the shareholder rights plan described later in this note. On April 25, 2003, the Board
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
increased the designated shares from 2.0 million to 2.9 million. At December 31, 2004, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $1.00 or 200 times the aggregate per share amount of all dividends (other than stock dividends) declared on common stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 200 votes per share (subject to adjustment to prevent dilution) on all matters submitted to a vote of the stockholders. The Series A Junior Preferred Stock is neither redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to the common stock but junior to all other classes of Preferred Stock.
On September 27, 2004, Devon announced a stock buyback program to repurchase up to 50 million shares of its common stock. During 2004, Devon repurchased 5 million shares at a total cost of $189 million, or $37.78 per share. Devon intends to continue repurchasing its shares in the open market and in privately negotiated transactions, depending upon market conditions. The stock repurchase program may be discontinued at any time.
The following is a summary of the changes in Devon’s common shares outstanding for 2004, 2003 and 2002:
Stock Option Plans
Devon has outstanding stock options issued to key management and professional employees under three stock option plans adopted in 1993, 1997 and 2003 (the “1993 Plan,” the “1997 Plan” and the “2003 Plan”). Options granted under the 1993 Plan and 1997 Plan remain exercisable by the employees owning such options, but no new options will be granted under these plans. At December 31, 2004, there were 202,000 and 8,774,000 options outstanding under the 1993 Plan and the 1997 Plan, respectively.
On April 25, 2003, Devon’s stockholders adopted the 2003 Long-Term Incentive Plan. The new long-term incentive plan authorizes the compensation committee of Devon’s Board of Directors to grant nonqualified and incentive stock options, stock appreciation rights, restricted stock awards, performance units and performance bonuses to selected employees. The plan also authorizes the grant of nonqualified stock options and restricted stock awards to directors. A total of 25,000,000 shares of Devon common stock have been reserved for issuance pursuant to the plan. Of these shares, no more than 5,000,000 shares may be granted as restricted stock, performance bonuses and performance units. During 2004 and 2003, 1,703,000 and 1,306,000 restricted stock awards, respectively, were granted which are subject to pro rata vesting over a four-year period. These awards had an aggregate fair value of $66 million and $34 million in 2004 and 2003, respectively, and will be recorded as compensation expense over the vesting period.
The exercise price of stock options granted under the 2003 Plan may not be less than the estimated fair market value of the stock at the date of grant. Options granted are exercisable during a period
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
established for each grant, which period may not exceed eight years from the date of grant. Under the 2003 Plan, the grantee must pay the exercise price in cash or in common stock, or a combination thereof, at the time that the option is exercised. The 2003 Plan is administered by a committee comprised of non-management members of the Board of Directors. The 2003 Plan expires on April 25, 2013. As of December 31, 2004, there were 5,906,000 options outstanding under the 2003 Plan. There were 16,022,000 options available for future grants as of December 31, 2004.
In addition to the stock options outstanding under the 1993 Plan, 1997 Plan and 2003 Plan there were approximately 2,739,000, 363,000, 200,000 and 1,591,000 stock options outstanding at the end of 2004 that were assumed as part of the Ocean merger, the Mitchell merger, the Santa Fe Snyder merger and the PennzEnergy merger, respectively.
A summary of the status of Devon’s stock option plans as of December 31, 2002, 2003 and 2004, and changes during each of the years then ended, is presented below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes information about Devon’s stock options which were outstanding, and those which were exercisable, as of December 31, 2004:
Shareholder Rights Plan
Under Devon’s shareholder rights plan, stockholders have one half of one right for each share of common stock held. The rights become exercisable and separately transferable ten business days after (a) an announcement that a person has acquired, or obtained the right to acquire, 15% or more of the voting shares outstanding, or (b) commencement of a tender or exchange offer that could result in a person owning 15% or more of the voting shares outstanding.
Each right entitles its holder (except a holder who is the acquiring person) to purchase either (a) 1/100 of a share of Series A Preferred Stock for $185.00, subject to adjustment or, (b) Devon common stock with a value equal to twice the exercise price of the right, subject to adjustment to prevent dilution. In the event of certain merger or asset sale transactions with another party or transactions which would increase the equity ownership of a shareholder who then owned 15% or more of Devon, each Devon right will entitle its holder to purchase securities of the merging or acquiring party with a value equal to twice the exercise price of the right.
The rights, which have no voting power, expire on August 17, 2009. The rights may be redeemed by Devon for $.01 per right until the rights become exercisable.
Dividends
Dividends on Devon’s common stock were paid in 2004 at a per share rate of $0.05 per quarter. Dividends on Devon’s common stock were paid in 2003 and 2002 at a per share rate of $0.025 per quarter.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
12.
Financial Instruments
The following table presents the carrying amounts and estimated fair values of Devon’s financial instrument assets (liabilities) at December 31, 2004 and 2003.
The following methods and assumptions were used to estimate the fair values of the financial instruments in the above table. The carrying values of cash and cash equivalents, short-term investments, accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 2004 and 2003.
Investment in ChevronTexaco Corporation common stock - The fair value of this investment is based on a quoted market price.
Oil and Gas Price Hedge Agreements - The fair values of the oil and gas price hedges are based on either (a) an internal discounted cash flow calculation, (b) quotes obtained from the counterparty to the hedge agreement or (c) quotes provided by brokers.
Interest Rate Swap Agreements - The fair values of the interest rate swaps are based on internal discounted cash flow calculations, using market quotes of future interest rates, or quotes obtained from counterparties.
Electricity Hedge Agreements - The fair values of the electricity hedges are based on internal discounted cash flow calculations.
Embedded Option in Exchangeable Debentures - The fair value of the embedded option is based on a quote obtained from a broker.
Long-term Debt - The fair values of the fixed-rate long-term debt are based on quotes obtained from brokers or by discounting the principal and interest payments at rates available for debt of similar terms and maturity. The fair values of the floating-rate long-term debt are estimated to approximate the carrying amounts due to the fact that the interest rates paid on such debt are generally set for periods of three months or less.
Preferred Stock of a Subsidiary - The fair value of the preferred stock is based upon quotes obtained from brokers.
Devon’s total hedged positions as of December 31, 2004 are set forth in the following tables.
Price Swaps
Through various price swaps, Devon has fixed the price it will receive on a portion of its oil and natural gas production in 2005. These swaps will result in the fixed prices included below. Where
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
necessary, the oil and gas prices related to these swaps have been adjusted for certain transportation costs that are netted against the price recorded by Devon, and the gas price has also been adjusted for the Btu content of the production that has been hedged.
Oil Production
Gas Production
Costless Price Collars
Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2005 oil production that is otherwise subject to floating prices. The floor and ceiling prices related to domestic and Canadian oil production are based on the NYMEX price. The floor and ceiling prices related to international oil production are based on the Brent price. If the NYMEX or Brent price is outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. As long as Devon meets the ongoing requirements of hedge accounting for its derivatives, any such settlements will either increase or decrease Devon’s oil revenues for the period. Because Devon’s oil volumes are often sold at prices that differ from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus heavy or sour crude) and transportation costs from different geographic areas, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2005 natural gas production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
The floor and ceiling prices shown in the following table are weighted averages of the various collars. The international oil prices shown in the following table have been adjusted to a NYMEX-based price, using Devon’s estimates of 2005 differentials between NYMEX and the Brent price upon which the collars are based.
The natural gas prices shown in the following table have been adjusted to a NYMEX-based price, using Devon’s estimates of future differentials between NYMEX and the specific regional indices upon
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
which the collars are based. The floor and ceiling prices related to the collars are based on various regional first-of-the-month price indices as published monthly by Inside FERC.
Oil Production
Gas Production
Interest Rate Swaps
Devon has also entered into a floating-to-fixed interest rate swap and fixed-to-floating interest rate swaps. Under the floating-to-fixed interest rate swap, Devon will record a fixed rate of 6.4% on a notional amount of $104 million in 2005 and 2006 and 6.3% on a notional amount of $32 million in 2007. Following is a table summarizing the fixed-to-floating interest rate swaps with the related debt instrument and notional amounts.
(1)
Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8308 as of December 31, 2004.
13.
Retirement Plans
Devon has various non-contributory defined benefit pension plans, including qualified plans (“Qualified Plans”) and nonqualified plans (“Supplemental Plans”). The Qualified Plans provide retirement benefits for U.S. and Canadian employees meeting certain age and service requirements. Benefits for the Qualified Plans are based on the employee’s years of service and compensation and are funded from assets held in the plans’ trusts.
During 2002, Devon established a funding policy regarding the Qualified Plans such that it would contribute the amount of funds necessary so that the Qualified Plans’ assets would be approximately equal to the related accumulated benefit obligation by the end of 2004. As of December 31, 2004, the fair value of the Qualified Plans’ assets was $456 million, which was $11 million more than the related accumulated benefit obligation. The actual amount of contributions required during future periods will depend on
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
investment returns from the plan assets during the same period as well as changes in long-term interest rates.
The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are limited by income tax regulations. The Supplemental Plans’ benefits are based on the employee’s years of service and compensation. For certain Supplemental Plans, Devon has established trusts to fund these plans’ benefit obligations. The total values of these trusts were $60 million and $66 million at December 31, 2004 and 2003, respectively, and are included in noncurrent other assets in the consolidated balance sheets. For the remaining Supplemental Plans for which trusts have not been established, benefits are funded from Devon’s available cash and cash equivalents.
Devon also has defined benefit postretirement plans (“Postretirement Plans”) which provide benefits for substantially all employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. Benefit obligations for the Postretirement Plans are estimated based on future cost-sharing changes that are consistent with Devon’s expressed intent to increase, where possible, contributions from future retirees. Devon’s funding policy for the Postretirement Plans is to fund the benefits as they become payable with available cash and cash equivalents.
Benefit Obligations
Devon uses a measurement date of December 31 for its pension and postretirement benefit plans. The following table presents the plans’ benefit obligations and the weighted-average actuarial assumptions used to calculate such obligations at December 31, 2004 and 2003. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for pension plans at December 31, 2004 and 2003 was $542 million and $475 million, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits, excluding prescription benefits, was assumed for 2005. The rate was assumed to decrease one percent annually to 5% in the year 2010 and remain at that level thereafter. Additionally, an 11% annual rate of increase in the per capita cost of covered prescription benefits was assumed for 2005. The rate was assumed to decrease approximately one percent annually to 5.25% in the year 2010 and remain at that level thereafter. A one-percentage-point increase in assumed health care cost trend rates would increase the December 31, 2004 postretirement benefit obligation by $2 million, while a one-percentage-point decrease in the same rate would decrease the postretirement benefit obligation by $1 million.
Plan Assets
The following table presents the plans’ assets at December 31, 2004 and 2003.
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The plan assets for pension benefits in the table above excludes the assets held in trusts for the Supplemental Plans. However, employer contributions for pension benefits in the table above include $6 million in 2004 and $22 million in 2003 which were transferred from the trusts established for the Supplemental Plans.
Devon’s overall investment objective for its retirement plans’ assets is to achieve long-term growth of invested capital to ensure payments of retirement benefits obligations can be funded when required. To assist in achieving this objective, Devon has established certain investment strategies, including target allocation percentages and permitted and prohibited investments, designed to mitigate risks inherent with investing. At December 31, 2004, the target investment allocation for Devon’s plan assets is 50% U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between growth and value; 15% international equity securities, equally allocated between growth and value; and 20% debt securities. Derivatives or other speculative investments considered high-risk are generally prohibited.
The asset allocation for Devon’s retirement plans at December 31, 2004 and 2003, and the target allocation for 2005, by asset category, follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Funded Status
The following table presents the funded status of the plans and the net amounts recognized in the consolidated balance sheets at December 31, 2004 and 2003.
During 2004 and 2003, the pre-tax change in the minimum pension liability increased other comprehensive income by $61 million and $28 million, respectively. During 2002, the pre-tax change in the minimum pension liability decreased other comprehensive income by $85 million.
Certain of Devon’s pension and postretirement plans have a projected benefit obligation in excess of plan assets at December 31, 2004 and 2003. The aggregate benefit obligation and fair value of plan assets for these plans is included below.
Certain of Devon’s pension plans have an accumulated benefit obligation in excess of plan assets at December 31, 2004 and 2003. The aggregate accumulated benefit obligation and fair value of plan assets for these plans is included below.
The plan assets included in the tables above exclude the Supplemental Plan trusts which had a total value of $60 million and $66 million at December 31, 2004 and 2003, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Net Periodic Cost
The following table presents the plans’ net periodic benefit cost and the weighted-average actuarial assumptions used to calculate such cost for the years ended December 31, 2004, 2003 and 2002.
The expected rate of return on plan assets was determined by evaluating input from external consultants and economists as well as long-term inflation assumptions. The expected long-term rate of return on plan assets is based on the target allocation of investment types in such assets.
Assumed health care cost trend rates have a significant effect on the amounts reported for the other postretirement benefit plans. A one-percentage-point change in the assumed health care cost trend rates would affect the total service and interest cost by less than $1 million.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”) was signed into law. The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004 the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). If the benefit provided is at least actuarially equivalent to Medicare Part D, FSP 106-2 requires companies to account for the effect of the subsidy on benefits attributable to past service as an actuarial experience gain that reduces the accumulated postretirement benefit obligation and for benefits attributable to current service as a reduction of the service cost included in net periodic benefit cost. FSP 106-2 is effective for the first interim period beginning after June 15, 2004. Because benefits provided to certain participants in the Postretirement Plans will be at least actuarially equivalent to Medicare Part D, Devon will be entitled to some subsidy. As a result, Devon reduced the accumulated postretirement benefit obligation at July 1, 2004, by $4 million and the net periodic postretirement benefit cost by $0.2 million for the year ended December 31, 2004.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Expected Cash Flows
Information about the expected cash flows for the pension and other postretirement benefit plans follows:
Expected employer contributions included in the table above include amounts related to Devon’s Qualified Plans, Supplemental Plans and Postretirement Plans. Of the benefits expected to be paid in 2005, $6 million is expected to be funded from the trusts established for the Supplemental Plans and $6 million is expected to be funded from Devon’s available cash and cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of employee contributions.
Other Benefit Plans
Devon has incurred certain postemployment benefits to former or inactive employees who are not retirees. These benefits include salary continuance, severance and disability health care and life insurance. The accrued postemployment benefit liability was approximately $5 and $6 million at December 31, 2004 and 2003, respectively.
Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a certain percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the Board of Directors. Devon’s matching contributions to the plan were $11 million, $10 million and $8 million for the years ended December 31, 2004, 2003 and 2002, respectively.
Devon has defined contribution pension plans for its Canadian employees. Devon makes a contribution to each employee which is based upon the employee’s base compensation and classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada). Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes a base percentage amount to all employees and the employee may elect to contribute an additional percentage amount (up to a maximum amount) which is matched by additional Devon contributions. During 2004, 2003 and 2002, Devon’s combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $9 million, $8 million and $8 million, respectively.
14.
Commitments and Contingencies
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
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 materially from management’s estimate.
Environmental Matters
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 December 31, 2004, 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.
Royalty Matters
Numerous gas producers and related parties, including Devon, have been named in various lawsuits 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 principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally filed in August 1996 in the United States District Court for the Eastern District of Texas, but was consolidated in October 2000 with the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Trial is set for February 2007 if the suit continues to advance. Devon believes that it has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded in connection therewith.
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. A significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
Tax Treatment of Exchangeable Debentures
As described more fully in Note 8, Devon has certain exchangeable debentures, with a principal amount totaling $760 million, which are exchangeable at the option of the holders into shares of ChevronTexaco common stock owned by Devon. The debentures were assumed, and the ChevronTexaco common stock was acquired, by Devon in the 1999 PennzEnergy merger.
The Internal Revenue Service (“IRS”) recently examined the 1998 income tax return of PennzEnergy’s predecessor, and the IRS formally notified Devon in April 2004 that it disagreed with certain tax treatments of the exchangeable debentures and similar exchangeable debentures retired in 1998. Devon did not agree with the IRS positions and contested the claim of additional taxes. In June 2004, Devon formally protested the IRS notice and requested a conference with the IRS Appeals Office. A preliminary appeals conference was held in October 2004, and additional appeals meetings were held in November and December 2004. This matter was resolved in February 2005, when the IRS agreed with Devon and concluded that no taxes were due.
Other Matters
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.
Operating Leases
Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in general and administrative expenses under operating leases, net of sub-lease income, was $49 million, $51 million and $37 million in 2004, 2003 and 2002, respectively.
Devon assumed two offshore platform spar leases through the 2003 Ocean merger. The spars are being used in the development of the Nansen and Boomvang fields in the Gulf of Mexico. The operating leases are for 20-year terms and contain various options whereby Devon may purchase the lessors’ interests in the spars. Total rental expense included in lease operating expenses under these operating leases was $17 million and $11 million in 2004 and 2003, respectively. Devon has guaranteed that the spars will have residual values at the end of the operating leases equal to at least 10% of the fair value of the spars at the inception of the leases. The total guaranteed value is $20 million in 2022. However, such amount may be reduced under the terms of the lease agreements.
Devon also has two floating, production, storage and offloading facilities (“FPSO”) that are being leased under operating lease arrangements. One FPSO is being used in the Panyu project offshore China, and the other is being used in the Zafiro field offshore Equatorial Guinea. The China lease expires in September 2009 and the Equatorial Guinea lease expires in July 2009. Total rental expense included in lease operating expenses under these operating leases was $20 million and $6 million in 2004 and 2003, respectively.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following is a schedule by year of future minimum rental payments required under office and equipment, spar and FPSO leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2004:
15.
Reduction of Carrying Value of Oil and Gas Properties
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. The ceiling is determined separately by country. In calculating future net revenues, prices and costs used are those as of the end of the appropriate quarterly period. These prices are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Devon has entered into various derivative instruments that are accounted for as cash flow hedges. These instruments, which consist of price swaps and costless price collars, and the related future production volumes, are discussed in Note 12. The effect of these hedges has been considered in calculating the full cost ceiling limitations as of December 31, 2004. These hedges reduced the full cost ceiling limitations for the United States, Canada and Equatorial Guinea as of the end of 2004 by $102 million, $77 million and $76 million, respectively. However, the 2004 capitalized costs in these countries did not exceed the related ceiling limitations, with or without the effects of the hedges.
The net book value, less related deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
Under the purchase method of accounting for business combinations, acquired oil and gas properties are recorded at estimated fair value as of the date of purchase. Devon estimates such fair value using its estimates of future oil, gas and NGL prices. In contrast, the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indefinitely. Accordingly, the resulting value from the ceiling calculation is not necessarily indicative of the fair value of the reserves.
During 2003 and 2002, Devon reduced the carrying value of its oil and gas properties by $68 million and $651 million, respectively, due to the full cost ceiling limitations. The after-tax effects of these
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
reductions in 2003 and 2002 were $36 million and $371 million, respectively. The following table summarizes these reductions by geographic area.
The 2003 reduction in carrying value was related to properties in Egypt, Russia and Indonesia. The Egyptian reduction was primarily due to poor results of a development well that was unsuccessful in the primary objective. Partially as a result of this well, Devon revised Egyptian proved reserves downward. The Russian reduction was primarily the result of additional capital costs incurred as well as an increase in operating costs. The Indonesian reduction was primarily related to an increase in operating costs and a reduction in proved reserves. As a result, Devon’s Egyptian, Russian and Indonesian costs to be recovered exceeded the related ceiling value by $26 million, $9 million and $1 million, respectively. These after-tax amounts resulted in pre-tax reductions of the carrying values of Devon’s Egyptian, Russian and Indonesian oil and gas properties of $45 million, $19 million and $4 million, respectively, in the fourth quarter of 2003.
Additionally, during 2003, Devon elected to discontinue certain exploratory activities in Ghana, certain properties in Brazil and other smaller concessions. After meeting the drilling and capital commitments on these properties, Devon determined that these properties did not meet Devon’s internal criteria to justify further investment. Accordingly, Devon recorded a $43 million charge associated with the impairment of these properties. The after-tax effect of this reduction was $38 million.
The 2002 Canadian reduction was primarily the result of lower prices. The recorded values of oil and gas properties added from the Anderson acquisition in 2001 were based on expected future oil and gas prices that were higher than the June 30, 2002, prices used to calculate the Canadian ceiling.
16.
Discontinued Operations
On April 18, 2002, Devon sold its Indonesian operations to PetroChina Company Limited for total cash consideration of $250 million. On October 25, 2002, Devon sold its Argentine operations to Petroleo Brasileiro S.A. for total cash consideration of $90 million. On January 27, 2003, Devon sold its Egyptian operations to IPR Transoil Corporation for total cash consideration of $7 million.
As a result, Devon reclassified its Indonesian, Argentine and Egyptian activities as discontinued operations. This reclassification affects the 2002 presentation of financial results. Subsequent to the sale of its Egyptian and Indonesian operations, Devon acquired new Egyptian and Indonesian assets in the April 2003 Ocean merger. Amounts and activities related to these new Egyptian and Indonesian operations are included in Devon’s continuing operations in 2004 and 2003. The revenues from these discontinued operations for the year ended December 31, 2002 (in millions) are presented below:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
17.
Segment Information
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. Certain information regarding such activities for each segment is included in Note 18.
Following is certain financial information regarding Devon’s segments for 2004, 2003 and 2002. The revenues reported are all from external customers.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
18.
Supplemental Information on Oil and Gas Operations (Unaudited)
The following supplemental unaudited information regarding the oil and gas activities of Devon is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, Disclosures About Oil and Gas Producing Activities.
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses which are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $172 million, $140 million and $97 million in the years 2004, 2003 and 2002, respectively. Also, Devon capitalizes interest costs incurred and attributable to unproved oil and gas properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs shown in the preceding tables, were $70 million, $50 million and $4 million in the years 2004, 2003 and 2002, respectively.
The preceding Total and International cost incurred tables exclude $16 million in 2002 related to discontinued operations.
As discussed in Note 1, effective January 1, 2003, Devon adopted SFAS No. 143. Prior to the adoption of SFAS No. 143, asset retirement costs were included in costs incurred when expenditures for such costs were made. Pursuant to the adoption of SFAS No. 143, such costs are now included in costs incurred when a legal obligation for incurring such costs has occurred.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Results of Operations for Oil and Gas Producing Activities
The following tables include revenues and expenses associated directly with Devon’s oil and gas producing activities, including general and administrative expenses directly related to such producing activities. They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The preceding Total and International results of oil and gas producing activities tables exclude $19 million in 2002 related to discontinued operations.
Quantities of Oil and Gas Reserves
Set forth below is a summary of the reserves which were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2004, 2003 and 2002.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
“Prepared” reserves are those estimates of quantities of reserves which were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of revenues which were estimated by Devon employees and audited by an independent petroleum consultant. An audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation principles.
The domestic reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company, L.P. in each of the years presented. The Canadian reserves were evaluated by the independent petroleum consultants of AJM Petroleum Consultants in each of the years presented. The International reserves were evaluated by the independent petroleum consultants of Ryder Scott Company, L.P. in each of the years presented.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Set forth below is a summary of the changes in the net quantities of crude oil, natural gas and natural gas liquids reserves for each of the three years ended December 31, 2004.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The preceding International quantities of reserves are attributable to production sharing contracts with various foreign governments.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The preceding Total and International quantities of oil and gas reserves tables exclude the following proved reserves and proved developed reserves related to discontinued operations.
Standardized Measure of Discounted Future Net Cash Flows
The accompanying tables reflect the standardized measure of discounted future net cash flows relating to Devon’s interest in proved reserves:
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Future cash inflows are computed by applying year-end prices (averaging $34.69 per barrel of oil, $5.27 per Mcf of gas and $29.73 per barrel of natural gas liquids at December 31, 2004) to the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements in existence at year-end. Such arrangements include derivatives accounted for as cash flow hedges.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Of the $4.3 billion of future development costs, $818 million, $588 million and $388 million are estimated to be spent in 2005, 2006 and 2007, respectively.
Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation costs. Included as part of the $4.3 billion of future development costs are $1.0 billion of future dismantlement, abandonment and rehabilitation costs.
Future production costs include general and administrative expenses directly related to oil and gas producing activities. Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The preceding Total and International standardized measure of discounted future net cash flows tables exclude $21 million in 2002 related to discontinued operations.
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net cash flows attributable to Devon’s proved reserves are as follows:
The preceding table excludes $21 million and $299 million as of December 31, 2002 and 2001, respectively, related to discontinued operations.
19.
Supplemental Quarterly Financial Information (Unaudited)
Following is a summary of the unaudited interim results of operations for the years ended December 31, 2004 and 2003.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The second and fourth quarters of 2004 include a $28 million and $8 million income tax benefit, respectively, due to statutory rate reductions of Canadian tax rates. The per share effect of these tax benefits were $0.06 and $0.01 in the second and fourth quarters of 2004, respectively.
The fourth quarter of 2003 includes a $218 million income tax benefit due to a statutory rate reduction of Canadian tax rates. The per share effect of this tax benefit was $0.45. The fourth quarter of 2003 also includes $111 million of reduction of carrying value of oil and gas properties. The after-tax effect of the reduction in carrying value was $74 million, or $0.16 per share.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A.
Item 9A.
Controls and Procedures
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation, Devon’s principal executive and principal financial officers have concluded that Devon’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of December 31, 2004 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Management’s Annual Report on Internal Control Over Financial Reporting
Devon’s management is responsible for establishing and maintaining adequate internal control over financial reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the participation of Devon’s management, including our principal executive and principal financial officers, Devon conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Based on this evaluation under the COSO Framework which was completed on February 18, 2005, management concluded that its internal control over financial reporting was effective as of December 31, 2004.
Management’s assessment of the effectiveness of Devon’s internal control over financial reporting as of December 31, 2004 has been audited by KPMG LLP, an independent registered public accounting firm who audited Devon’s consolidated financial statements as of and for the year ended December 31, 2004, as stated in their report which is included herein.
Changes in Internal Control Over Financial Reporting
There was no change in Devon’s internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, Devon’s internal control over financial reporting.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting that Devon Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Devon Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Devon Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 4, 2005 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Oklahoma City, Oklahoma
March 4, 2005
Item 9B.
Item 9B.
Other Information
On February 16, 2005, we redeemed the one outstanding share of our special voting preferred stock.
On March 7, 2005 we filed a Certificate of Elimination with the State of Delaware that amended our certificate of incorporation by eliminating all references to the special voting preferred stock. We then filed a restated certificate of incorporation with the State of Delaware that integrated that amendment into our certificate of incorporation, but did not further amend it. The restated certificate of incorporation is attached as an exhibit to this document.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
The information called for by this Item 10 is incorporated hereby by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 29, 2005.
Item 11.
Item 11.
Executive Compensation
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 29, 2005.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 29, 2005.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 29, 2005.
Item 14.
Item 14.
Principal Accountant Fees and Services
The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 29, 2005.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statements Schedules
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at Item 8 in this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits
*
Compensatory plans or arrangements
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.
Devon Energy Corporation
By:
/s/ J. Larry Nichols
J. Larry Nichols,
Chairman of the Board and
Chief Executive Officer
March 7, 2005
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
INDEX TO EXHIBITS
*
Compensatory plans or arrangements