-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TXnZxatiA3QyaJE8lwhFdvdxPB1EjupPasP8YcGSy/bd6VOAlL3/irVzykwaZFPO hQ2IUS2C8mgSkIDZF1uY4A== 0000950134-00-002693.txt : 20030527 0000950134-00-002693.hdr.sgml : 20030526 20000329213200 ACCESSION NUMBER: 0000950134-00-002693 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 DATE AS OF CHANGE: 20000602 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DEVON ENERGY CORP/DE CENTRAL INDEX KEY: 0001090012 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 731567067 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 000-30176 FILM NUMBER: 00584620 BUSINESS ADDRESS: STREET 1: 20 N BROADWAY STREET 2: STE 1500 CITY: OKLAHOMA CITY STATE: OK ZIP: 73102 BUSINESS PHONE: 4052353611 MAIL ADDRESS: STREET 1: 20 N BROADWAY STREET 2: STE 1500 CITY: OKLAHOMA CITY STATE: OK ZIP: 73102 FORMER COMPANY: FORMER CONFORMED NAME: DEVON DELAWARE CORP DATE OF NAME CHANGE: 19990707 10-K405 1 FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 1999 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE - - - - - - - - ----- SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1999 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE - - - - - - - - ------ SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-30176 DEVON ENERGY CORPORATION (Exact Name of Registrant as Specified in its Charter) DELAWARE 73-1567067 (State or Other Jurisdiction of (I.R.S. Employer Incorporation or Organization) Identification No.) 20 NORTH BROADWAY, SUITE 1500 OKLAHOMA CITY, OKLAHOMA 73102-8260 (Address of Principal Executive Offices) (Zip Code) Registrant's telephone number, including area code: (405) 235-3611 Securities registered pursuant to Section 12(b) of the Act: NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- Common Stock, par value $.10 per share American Stock Exchange 4.9% Convertible Debentures, due 2008 The New York Stock Exchange 4.95% Convertible Debentures, due 2008 The New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR AT LEAST THE PAST 90 DAYS. YES X NO --- --- INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. X --- The aggregate market value of the voting stock held by non-affiliates of the Registrant as of March 15, 2000, was $3,465,818,453. At such date 81,763,318 shares of common stock and 4,583,804 exchangeable shares of Devon's wholly-owned subsidiary, Northstar Energy Corporation, were outstanding. Each exchangeable share is exchangeable for one share of Devon common stock. DOCUMENTS INCORPORATED BY REFERENCE Proxy statement for the 2000 annual meeting of stockholders - Part III 2 TABLE OF CONTENTS
Page ---- PART I Item 1. Business................................................................................ 4 Item 2. Properties.............................................................................. 12 Item 3. Legal Proceedings....................................................................... 18 Item 4. Submission of Matters to a Vote of Security Holders..................................... 20 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................... 21 Item 6. Selected Financial Data................................................................. 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations... 25 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.............................. 45 Item 8. Financial Statements and Supplementary Data............................................. 47 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.... 105 PART III Item 10. Directors and Executive Officers of the Registrant..................................... 105 Item 11. Executive Compensation................................................................. 105 Item 12. Security Ownership of Certain Beneficial Owners and Management......................... 105 Item 13. Certain Relationships and Related Transactions......................................... 105 PART IV Item 14. Exhibits, Financial Statements and Schedules, and Reports on Form 8-K.................. 106
DEFINITIONS As used in this document: "Mcf" means thousand cubic feet "MMcf" means million cubic feet "Bcf" means billion cubic feet "MMBtu" means million British thermal units, a measure of heating value "Bbl" means barrel "MBbls" means thousand barrels "MMBbls" means million barrels "Boe" means equivalent barrels of oil "MBoe" means thousand equivalent barrels of oil "MMBoe" means million equivalent barrels of oil "Oil" includes crude oil and condensate "NGLs" means natural gas liquids "Southern Division" means the division of the Company encompassing oil and gas properties located primarily in the onshore south Texas and Gulf Coast areas and offshore in the Gulf of Mexico "Northern Division" means the division of the Company encompassing oil and gas properties located in the United States other than those within the Southern Division "International Division" means the division of the Company encompassing oil and gas properties that lie outside the United States and Canada "Canada" means the division of the Company encompassing oil and gas properties that are located in Canada. All of these properties are held in the Company's wholly-owned subsidiary, Northstar Energy Corporation. 2 3 DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS THIS REPORT INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF SECTION 27A OF THE SECURITIES ACT OF 1933, AS AMENDED, AND SECTION 21E OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED OR INCORPORATED BY REFERENCE IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE COMPANY'S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS "MAY," "WILL," "EXPECT," "INTEND," "PROJECT," "ESTIMATE," "ANTICIPATE," "BELIEVE," OR "CONTINUE" OR THE NEGATIVE THEREOF OR VARIATIONS THEREON OR SIMILAR TERMINOLOGY. ALTHOUGH THE COMPANY BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO HAVE BEEN CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE COMPANY'S EXPECTATIONS ("CAUTIONARY STATEMENTS") ARE DISCLOSED UNDER "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS," "ITEM 2. PROPERTIES - PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE" AND ELSEWHERE IN THIS REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE COMPANY, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THE CAUTIONARY STATEMENTS. THE COMPANY ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE. 3 4 PART I ITEM 1. BUSINESS GENERAL Devon Energy Corporation, including its subsidiaries, ("Devon" or the "Company") is an independent energy company engaged primarily in oil and gas exploration, development and production, and in the acquisition of producing properties. Through its predecessors, Devon began operations in 1971 as a privately-held company. In 1988 the Company's common stock began trading publicly on the American Stock Exchange under the symbol DVN. In addition, commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange under the symbol NSX. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon's wholly-owned subsidiary, Northstar Energy Corporation ("Northstar"), they qualify as a domestic Canadian investment for Canadian institutional shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon. The principal and administrative offices of Devon are located at 20 North Broadway, Suite 1500, Oklahoma City, OK 73102-8260 (telephone 405/235-3611). Devon currently owns oil and gas properties concentrated in four operating divisions: the Northern Division, which encompasses properties in the Permian Basin, Rocky Mountains and Mid-Continent; the Southern Division, which encompasses properties in south Texas, the Gulf Coast area and offshore Gulf of Mexico; Canada, which includes properties in the Western Canadian Sedimentary Basin in Alberta and British Columbia; and the International Division, which includes properties in Azerbaijan, Egypt, Qatar, Brazil, Australia and Venezuela. (A detailed description of the significant properties can be found under "Item 2. Properties - Significant Properties" beginning on page 12 hereof.) At December 31, 1999, Devon's estimated proved reserves were 669.8 MMBoe, of which 47% were natural gas reserves and 53% were oil and NGLs reserves. The present value of pre-tax future net revenues discounted at 10% per annum assuming essentially unescalated prices ("10% Present Value") of such reserves was $3.6 billion. Devon is one of the top 10 public independent oil and gas companies based in the United States, as measured by oil and gas reserves. STRATEGY Devon's primary objectives are to build production, cash flow and earnings per share by (a) acquiring oil and gas properties, (b) exploring for new oil and gas reserves and (c) optimizing production from existing oil and gas properties. Devon's management seeks to achieve these objectives by (a) keeping debt levels low, (b) concentrating its properties in core areas to achieve economies of scale, (c) acquiring and developing high profit margin properties, (d) continually disposing of marginal and non-strategic properties and (e) balancing reserves between oil and gas. 4 5 During 1988, Devon expanded its capital base with its first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. Devon has used a two-pronged strategy of acquiring producing properties and engaging in drilling activities to achieve this expansion. Total proved reserves increased from 8.1 MMBoe at year-end 1987 to 669.8 MMBoe at year-end 1999. Devon's objective, however, is to increase value per share, not simply to increase total assets. Reserves have grown from 1.31 Boe per share at year-end 1987 to 7.78 Boe per share at year-end 1999. At the same time, net debt (long-term debt less working capital and marketable securities) has remained relatively low. At year-end 1999, Devon's net debt was $1.47 per Boe. RECENT DEVELOPMENTS On August 17, 1999, Devon completed a merger with PennzEnergy Company ("PennzEnergy"). PennzEnergy's domestic operations were focused in the Gulf of Mexico, onshore Gulf Coast, east and west Texas, and New Mexico. It had international operations located in Australia, Azerbaijan, Brazil, Egypt, Qatar and Venezuela. The merger of PennzEnergy with Devon expanded Devon's reserves by approximately 396 MMBoe, approximately 13 million net acres of undeveloped leasehold and $3.2 billion of assets. The total consideration to PennzEnergy was 21.5 million common shares and the assumption of $2.3 billion of PennzEnergy debt. At year-end 1999, Devon's unused borrowing capacity was in excess of $435 million. The PennzEnergy merger was accounted for under the purchase method of accounting for business combinations. Therefore, Devon's 1999 results do not include any effect of PennzEnergy's operations prior to August 17, 1999. The PennzEnergy merger was completed less than a year after Devon's merger with Northstar. The December 10, 1998, combination of Devon and Northstar added 115 MMBoe of proved reserves and 1.8 million undeveloped acres, all in Canada. The Northstar combination was accounted for under the pooling-of-interests method of accounting for business combinations. Accordingly, Devon's results for 1998 and prior years include the results of both Devon and Northstar as if the two had always been combined. In addition to the two mergers, Devon's exploration, drilling and development efforts have also been significant contributors to Devon's growth over the last three years. Excluding the pooled results of Northstar prior to December 1998, Devon has spent approximately $492 million in its exploration, drilling and development efforts from 1997 through 1999. These costs included drilling 1,154 wells, of which 1,065 were completed as producers. DRILLING ACTIVITIES Devon is engaged in numerous drilling activities on properties presently owned and intends to drill or develop other properties acquired in the future. For 2000, Devon's drilling activities will be focused in the Rocky Mountains, Permian Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas in the U.S. and the Western Sedimentary areas of Canada. 5 6 The following tables set forth the results of Devon's drilling activity for the past five years. UNITED STATES PROPERTIES
Development Wells Exploratory Wells ---------------------------------------------------------- --------------------------------------------------------- Gross (1) Net (2) Gross (1) Net(2) ---------------------------------------------------------- --------------------------------------------------------- Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total ---------- --- ------ ---------- --- ------- ---------- --- ----- ---------- ----- ------- 1995 184 3 187 143.87 0.29 144.16 9 3 12 2.53 1.18 3.71 1996 188 3 191 137.05 0.95 138.00 2 1 3 1.50 0.08 1.58 1997 244 9 253 109.00 4.90 113.90 14 2 16 5.00 1.50 6.50 1998 328 0 328 128.69 0.00 128.69 14 4 18 7.36 1.44 8.80 1999 476 5 481 300.25 1.50 301.75 58 3 61 46.51 1.98 48.49 ------ --- ------ ------- ----- ------- --- --- ----- ------ ----- ------- Total 1,420 19 1,440 818.86 7.64 826.50 97 13 110 62.90 6.18 69.08 ====== === ====== ======= ===== ======= === === ===== ====== ===== =======
CANADIAN PROPERTIES
Development Wells Exploratory Wells ---------------------------------------------------------- --------------------------------------------------------- Gross (1) Net (2) Gross (1) Net(2) ---------------------------------------------------------- --------------------------------------------------------- Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total ---------- --- ------ ---------- --- ------- ---------- --- ----- ---------- ------ ------- 1995 44 8 52 25.20 5.20 30.40 48 13 61 35.70 10.00 45.70 1996 63 11 74 29.70 5.10 34.80 35 18 53 24.70 15.10 39.80 1997 126 29 155 88.20 23.20 111.40 55 48 103 43.50 42.20 85.70 1998 112 15 127 74.88 11.04 85.92 45 37 82 32.99 30.50 63.49 1999 65 9 74 29.61 3.45 33.06 39 23 62 25.15 16.03 41.18 ------ --- ------ ------- ----- ------- --- --- ----- ------ ------ ------- Total 410 72 482 247.59 47.99 295.58 222 139 361 162.04 113.83 275.87 ====== === ====== ======= ===== ======= === === ===== ====== ====== =======
INTERNATIONAL PROPERTIES
Development Wells Exploratory Wells ---------------------------------------------------------- --------------------------------------------------------- Gross (1) Net (2) Gross (1) Net(2) ---------------------------------------------------------- --------------------------------------------------------- Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total ---------- ----- ------ ---------- ----- ------- ---------- ----- ----- ---------- ----- ------- 1999 -- -- -- -- -- -- -- -- -- -- -- -- ------ --- ------ ------- ----- ------- --- --- ----- ------ ----- ------- Total -- -- -- -- -- -- -- -- -- -- -- -- ====== === ====== ======= ===== ======= === === ===== ====== ===== =======
TOTAL PROPERTIES
Development Wells Exploratory Wells ---------------------------------------------------------- --------------------------------------------------------- Gross (1) Net (2) Gross (1) Net(2) ---------------------------------------------------------- --------------------------------------------------------- Productive Dry Total Productive Dry Total Productive Dry Total Productive Dry Total ---------- ----- ------ ---------- ----- -------- ---------- ----- ----- ---------- ------- ------- 1995 228 11 239 169.07 5.49 174.56 57 16 73 38.23 11.18 49.41 1996 251 14 265 166.75 6.05 172.80 37 19 56 26.20 15.18 41.38 1997 370 38 408 197.20 28.10 225.30 69 50 119 48.50 43.70 92.20 1998 440 15 455 203.57 11.04 214.61 59 41 100 40.35 31.94 72.29 1999 541 14 555 329.86 4.95 334.81 97 26 123 71.66 18.01 89.67 ------ --- ------ --------- ----- -------- --- --- ----- ------ ------- ------- Total 1,830 92 1,922 1,066.45 55.63 1,122.08 319 152 471 224.94 120.01 344.95 ====== === ====== ========= ===== ======== === === ===== ====== ======= =======
- - - - - - - - ------------- (1) Gross wells are the sum of all wells in which Devon owns an interest. (2) Net wells are the sum of Devon's working interests in gross wells. As of December 31, 1999, Devon was participating in the drilling of 80 gross (50.30 net) wells in the U.S. and 8 gross (4.20 net) wells in Canada. Of these wells, through March 1, 2000, 23 gross (16.10 net) wells in the U.S. and 2 gross (.78 net) wells in Canada had been completed as productive. An additional 1 gross (0.60 net) well in the U.S. and 2 gross (1.17 net) wells in Canada were dry holes. The remaining wells were still in process. 6 7 CUSTOMERS Devon sells its gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Existing gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries. The principal customers for Devon's crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or barged to storage, refining or pipeline facilities. For the year ended December 31, 1999, one significant purchaser, Columbia Energy Services Corporation ("Columbia"), accounted for 12% of Devon's combined oil, gas and NGLs sales. For the years ended 1998 and 1997, one significant purchaser, Aquila Energy Marketing Corporation ("Aquila"), accounted for 19% and 15%, respectively, of Devon's total revenue. Columbia and Aquila purchase production from numerous Devon properties, at variable and market-sensitive prices. Devon does not consider itself dependent upon either of these purchasers, since other purchasers are willing to purchase this same production at competitive prices. OIL AND NATURAL GAS MARKETING Oil Marketing. Devon's oil production is sold under both long-term and short-term agreements at prices negotiated between the parties. Devon periodically enters into hedging activities with a portion of its oil production which are intended to support its oil price at targeted levels and to manage the Company's exposure to oil price fluctuations. (See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk.") Natural Gas Marketing. Devon's gas production is also sold under both long-term and short-term agreements at negotiated prices. Although exact percentages vary daily, as of March 2000 approximately 20% of Devon's natural gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as "spot market" sales. Another 65% were committed under various long-term contracts (one year or more) which dedicate the natural gas to a purchaser for an extended period of time, but still at market sensitive prices. Devon's remaining gas production was dedicated under long-term contracts at fixed prices. Under both long-term and short-term contracts, typically either the entire contract (in the case of short-term contracts) or the price provisions of the contract (in the case of long-term contracts) are renegotiated from daily intervals up to one-year intervals. The spot market has become progressively more competitive in recent years. As a result, prices on the spot market have been volatile. The spot market is subject to volatility as supply and demand factors in various regions of North America fluctuate. In addition to long-term fixed price contracts, Devon periodically enters into hedging arrangements or firm delivery commitments with a portion of its gas production. These activities are intended to support targeted gas price levels and to manage the Company's exposure to gas price fluctuations. (See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk.") 7 8 COMPETITION The oil and gas business is highly competitive. Devon encounters competition by major integrated and independent oil and gas companies in acquiring drilling prospects and properties, contracting for drilling equipment and securing trained personnel. Intense competition occurs with respect to marketing, particularly of natural gas. Certain competitors have resources that substantially exceed those of Devon. SEASONAL NATURE OF BUSINESS Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. GOVERNMENT REGULATION Devon's operations are subject to various levels of government controls and regulations in the United States, Canada and internationally. UNITED STATES REGULATION In the United States, legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas drilling and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, Devon is unable to predict the future cost or impact of complying with such laws and regulations. Exploration and Production. Devon's United States operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Devon's operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas Devon can produce from its wells and to limit the number of wells or the locations at which Devon can drill. 8 9 Certain of Devon's oil and gas leases, including most of its leases in the San Juan Basin and many of the Company's leases in southeast New Mexico and Wyoming, are granted by the federal government and administered by various federal agencies. Such leases require compliance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. Federal regulation of Devon's offshore Gulf of Mexico leases is accomplished by the Minerals Management Service of the Department of the Interior (`MMS"). The MMS has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands. The FERC also has jurisdiction over certain offshore activities pursuant to the Outer Continental Shelf Lands Act. Environmental and Occupational Regulations. Various federal, state and local laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of contaminants or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect Devon's exploration, development and production operations and the costs attendant thereto. These laws and regulations increase Devon's overall operating expenses. Devon maintains levels of insurance customary in the industry to limit its financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, 100% coverage is not maintained concerning any environmental claim, and no coverage is maintained with respect to any award of punitive damages against Devon or any penalty or fine required to be paid by Devon because of its violation of any federal, state or local law. Devon is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Devon's unreimbursed expenditures in 1999 concerning such matters were immaterial, but Devon cannot predict with any reasonable degree of certainty its future exposure concerning such matters. Devon is also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations, and the judicial construction of same, Devon is unable to predict with any reasonable degree of certainty its future costs of complying with these laws and regulations. Since 1993, Devon has had its own internal Environmental Health and Safety Department. This department is responsible for instituting and maintaining an environmental and safety compliance program for Devon. The program includes field inspections of properties and internal assessments of Devon's compliance procedures. 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 potential 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 claims for possible recovery from third party insurers or other parties related to environmental costs have been 9 10 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 the PennzEnergy merger 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, 1999, Devon's consolidated balance sheet included $6.7 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. 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) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material. CANADIAN REGULATIONS The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect Devon's Canadian operations in a manner materially different than they would affect other oil and gas companies of similar size. The following are the most important areas of control and regulation. The North American Free Trade Agreement. The North American Free Trade Agreement ("NAFTA") which became effective on January 1, 1994 carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not (i) reduce the proportion of energy exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements. Royalties and Incentives. Each province and the federal government of Canada have legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada, Alberta and British Columbia have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing the cash flow to the producer. Pricing and Marketing. The price of oil and natural gas sold is determined by negotiation between buyers and sellers. An order from the National Energy Board ("NEB") is required for oil exports from Canada. Any oil export to be made pursuant to an export contract of longer than one 10 11 year, in the case of light crude, and two years, in the case of heavy crude, duration (up to 25 years) requires an exporter to obtain an export license from the NEB. The issue of such a license requires the approval of the Governor in Council. Natural gas exported from Canada is also subject to similar regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations. Environmental Regulation. The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. Devon is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Devon's unreimbursed expenditures in 1999 concerning such matters were immaterial, but Devon cannot predict with any reasonable degree of certainty its future exposure concerning such matters. Investment Canada Act. The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval. INTERNATIONAL REGULATIONS Environmental Regulation. The oil and gas industry is subject to various environmental regulation and contract concession requirements pursuant to each individual country's laws, agreements, and treaties. In general, this consists of preparing Environmental Impact Assessments in order to receive required environmental permits to conduct any type of drilling or construction activity. Such regulations also typically include requirements to develop emergency response plans, waste management plans, and spill contingency plans. In some regions, the application of world-wide standards, such as, ISO 14000 governing Environmental Management Systems are required to be implemented for operations. Protecting the environment and the safety and health of employees, contractors, communities, and the public is fundamental to the way Devon conducts its business. This is accomplished through the establishment of corporate environmental, health, and safety policies and procedures that are implemented worldwide. EMPLOYEES As of December 31, 1999, Devon's staff consisted of 1,549 full-time employees, including 162 professionals in engineering, 90 in geology, 61 in the land department, 28 in oil and gas marketing, 226 in accounting and data processing, and 170 in administration and other support positions. Included in the number, are 148 former employees of PennzEnergy whose services will be terminated at various times during the year 2000. The Company also engages independent consulting petroleum engineers, 11 12 environmental professionals, geologists, geophysicists, landmen and attorneys on a fee basis. 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 the Company'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 volumetric production payments, and, to a lesser extent, overriding royalty, foreign government concessions, mineral and net profits interests and other forms of direct and indirect ownership in oil and gas properties. PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE "Proved reserves" are those quantities of oil, natural gas and NGLs, which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are strictly technical judgments and are not knowingly influenced by attitudes of conservatism or optimism. The following table sets forth Devon's estimated proved reserves, the estimated future net revenues therefrom and the 10% Present Value thereof as of December 31, 1999. Approximately 97% of Devon's U.S. proved reserves were estimated by LaRoche Petroleum Consultants, Ltd. and Ryder-Scott Company Petroleum Consultants, independent petroleum consultants. Devon's internal staff of engineers estimated the remainder of the U.S. reserves. All of the year-end 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates Ltd. The international proved reserves, other than Canada as of December 31, 1999, were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants. All reserve estimates were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines (as described in the following notes). These estimates correspond with the method used in presenting the `Supplemental Information on Oil and Gas Operations" in Note 16 to Devon's Consolidated Financial Statements included herein, except that federal income taxes attributable to such future net revenues have been disregarded in the presentation below. 12 13
TOTAL PROVED PROVED PROVED DEVELOPED UNDEVELOPED RESERVES RESERVES (1) RESERVES (2) ---------- ------------ ------------ TOTAL RESERVES Oil (MBbls) .................................... 303,917 171,249 132,668 Gas (MMcf) ..................................... 1,896,527 1,751,385 145,142 NGLs (MBbl) .................................... 49,817 47,502 2,315 MBoe (3) ....................................... 669,822 510,649 159,173 Pre-tax Future Net Revenue ($ thousands)(4) .... 6,712,759 4,843,728 1,869,031 Pre-tax 10% Present Value ($ thousands)(4) ..... 3,634,023 3,027,305 606,718 U.S. RESERVES Oil (MBbls) .................................... 145,524 128,167 17,357 Gas (MMcf) ..................................... 1,384,086 1,246,131 137,955 NGLs (MBbl) .................................... 45,804 43,637 2,167 MBoe (3) ....................................... 422,009 379,493 42,516 Pre-tax Future Net Revenue ($ thousands)(4) .... 4,094,550 3,740,386 354,164 Pre-tax 10% Present Value ($ thousands)(4) ..... 2,503,341 2,331,613 171,728 CANADIAN RESERVES Oil (MBbls) .................................... 32,132 29,268 2,864 Gas (MMcf) ..................................... 506,218 501,376 4,842 NGLs (MBbl) .................................... 4,013 3,865 148 MBoe (3) ....................................... 120,515 116,696 3,819 Pre-tax Future Net Revenue ($ thousands)(4) .... 1,084,902 1,032,242 52,660 Pre-tax 10% Present Value ($ thousands)(4) ..... 689,777 659,082 30,695 INTERNATIONAL RESERVES Oil (MBbls) .................................... 126,261 13,814 112,447 Gas (MMcf) ..................................... 6,223 3,878 2,345 NGLs (MBbl) .................................... -- -- -- MBoe (3) ....................................... 127,298 14,460 112,838 Pre-tax Future Net Revenue ($ thousands)(4) .... 1,533,307 71,100 1,462,207 Pre-tax 10% Present Value ($ thousands)(4) ..... 440,905 36,610 404,295
- - - - - - - - -------------------------- (1) Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods. (2) Proved undeveloped reserves are proved reserves to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompleting or deepening a well or for new fluid injection facilities. (3) Gas reserves are converted to MBoe at the rate of six MMcf per MBbl 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. The respective prices of gas and oil are affected by market conditions and other factors in addition to relative energy content. (4) Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and development costs. The amounts shown do not give effect to non-property related expenses such as general and administrative expenses, 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, 1999. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices over the life of Devon's properties of $21.96 per Bbl of oil, $1.87 per Mcf of natural gas and $15.74 per Bbl of NGLs. These prices compare to December 31, 1999, benchmark posted prices of $22.75 per Bbl for West Texas Intermediate crude oil and a composite of $2.03 per MMBtu for Texas Gulf Coast spot gas for gas delivered to various Texas Gulf Coast pipelines. 13 14 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, 1999. 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. The process of estimating oil, gas and NGLs reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data 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. PRODUCTION, REVENUE AND PRICE HISTORY Certain information concerning oil and natural gas production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 1999, 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, 1999:
Oil Wells Gas Wells Total Wells ------------------------ ------------------------- ------------------------ Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) ------------- ---------- ------------ ------------ ------------ ----------- U.S. 12,999 4,090 5,238 2,667 18,237 6,757 Canada 1,636 556 1,374 539 3,010 1,095 International 154 82 3 2 157 84 ------------- ---------- ------------ ------------ ------------ ----------- Total 14,789 4,728 6,615 3,208 21,404 7,936 ============= ========== ============ ============ ============ ===========
(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. Devon also held numerous overriding royalty interests in oil and gas wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding royalty interests will be included in Devon's gross and net well count. 14 15 UNDEVELOPED ACREAGE The following table sets forth Devon's developed and undeveloped oil and gas lease and mineral acreage as of December 31, 1999.
Developed Undeveloped ------------------------ ------------------------ Gross (1) Net (2) Gross (1) Net (2) ------------ ----------- ------------ ----------- Northern Division Permian Basin 582,390 259,741 793,033 201,473 Rocky Mountains 407,139 168,146 1,524,306 1,186,264 Mid-Continent & Other 1,253,368 867,184 927,140 412,232 ------------ ----------- ------------ ----------- Total Northern Division 2,242,897 1,295,071 3,244,479 1,799,969 ------------ ----------- ------------ ----------- Southern Division Offshore 320,056 207,908 501,649 371,713 Onshore 397,475 259,740 108,128 40,959 ------------ ----------- ------------ ----------- Total Southern Division 717,531 467,648 609,777 412,672 ------------ ----------- ------------ ----------- Canada 873,280 469,026 3,074,357 2,205,606 International Division 31,100 11,253 12,714,589 11,634,351 ------------ ----------- ------------ ----------- Grand Total 3,864,808 2,242,998 19,643,202 16,052,598 ============ =========== ============ ===========
(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. The charges under operating agreements customarily vary with the depth and location of the well being operated. Devon is the operator of 8,913 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 to or by unaffiliated third parties. 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. SIGNIFICANT PROPERTIES 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, 1999. 15 16
10% PRESENT VALUE(3) 10% PRESENT OIL(MBBLS) GAS(MMCF) NGLS(MBBL) MBOE(1) MBOE%(2) ($000) VALUE%(4) ---------- ---------- ---------- -------- --------- ----------- ----------- NORTHERN DIVISION Permian Basin 68,200 206,425 17,707 120,312 17.9% $ 797,017 21.9% Rocky Mountains 35,167 437,495 5,689 113,771 17.0% 602,810 16.6% Mid-Continent & Other 15,624 420,570 17,226 102,945 15.4% 535,211 14.7% ---------- ---------- ---------- -------- ----- ----------- ---------- Total 118,991 1,064,490 40,622 337,028 50.3% 1,935,038 53.2% ---------- ---------- ---------- -------- ----- ----------- ---------- SOUTHERN DIVISION Offshore 16,670 216,387 3,645 56,380 8.4% 376,828 10.4% Onshore 9,863 103,209 1,537 28,601 4.3% 191,475 5.3% ---------- ---------- ---------- -------- ----- ----------- ---------- Total 26,533 319,596 5,182 84,981 12.7% 568,303 15.7% ---------- ---------- ---------- -------- ----- ----------- ---------- Total U.S. 145,524 1,384,086 45,804 422,009 63.0% 2,503,341 68.9% ---------- ---------- ---------- -------- ----- ----------- ---------- CANADA Total 32,132 506,218 4,013 120,515 18.0% 689,777(5) 19.0% ---------- ---------- ---------- -------- ----- ----------- ---------- INTERNATIONAL DIVISION Total 126,261 6,223 -- 127,298 19.0% 440,905 12.1% ---------- ---------- ---------- -------- ----- ----------- ---------- Grand Total 303,917 1,896,527 49,817 669,822 100.0% $ 3,634,023 100.0% ========== ========== ========== ======== ===== =========== ==========
(1) Gas reserves are converted to MBoe at the rate of six MMcf of gas per MBbl 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. The respective prices of gas and oil are affected by market and other factors in addition to relative energy content. (2) Percentage which MBoe for the basin or region bears to total MBoe for all Proved Reserves. (3) Determined in accordance with SEC guidelines, except that no effect is given to future income taxes. (4) Percentages which present value for the basin or region bears to total present value for all Proved Reserves. (5) Canadian dollars converted to U.S. dollars at the rate of $1 Canadian: $0.6929 U.S. NORTHERN DIVISION PROPERTIES PERMIAN BASIN. This region encompasses approximately 66,000 square miles in southeastern New Mexico and west Texas and contains more than 500 major oil and gas fields. Since 1987, several significant acquisitions of properties by Devon in the Permian Basin have established prospective acreage in areas in which leasehold positions could not otherwise be obtained. It is characterized by prolific, long-lived oil and gas production from numerous formations found at a wide variety of depths. Many formations respond to enhanced recovery techniques, such as waterflood projects. In addition, the region is criss-crossed with multiple pipelines with easy access to many oil and gas markets. Acreage held by production from existing wells and large federal exploration units makes leases difficult to obtain. Most of Devon's position here was established through five major transactions. ROCKY MOUNTAINS. Over a dozen oil and gas producing basins are located in the Rocky Mountain area, stretching from the Canadian border south to New Mexico. The Rocky Mountain area includes Devon's operations in three coalbed methane basins: The San Juan Basin in northwest New Mexico and southern Colorado, the Powder River Basin in Wyoming and the Raton Basin of northeastern New Mexico. Technology pioneered by Devon and a few other companies in the 1980's and 1990's resulted in significant production from coalbeds in the San Juan Basin. Devon is now applying its expertise to the development of coalbed reservoirs in the Powder River and Raton Basins. Over the next few years, Devon anticipates significant growth in its gas production from these two basins as wells are drilled and tied into pipelines. 16 17 Devon's largest natural gas reserve position in the Rocky Mountain Region relates to its interests in two federal units in the San Juan Basin. The San Juan Basin is a densely drilled area covering 3,700 square miles. Devon's coal seam expertise will also play an important role in both the Powder River and Raton Basins. These basins, which are less developed than the San Juan Basin, have become two of the more active domestic onshore exploration areas in the United States. During the next five years, Devon plans to drill several thousand coalbed methane wells in the Powder River and Raton Basins which could, in aggregate, add significant proved natural gas reserves. Peak production for the Powder River Basin is anticipated for 2003, while peak production in the Raton Basin is estimated for 2004 to 2006. Additionally, Devon began initial operation of a 126-mile gas gathering system servicing the Powder River Basin in the third quarter of 1999. When it is fully developed in 2001, this system will have an estimated capacity of 450 million cubic feet of gas per day and will have access to multiple interstate pipelines. MID-CONTINENT. The Mid-Continent area includes all or portions of the states of Kansas, Oklahoma, Texas, Arkansas, Louisiana, Mississippi and Alabama. The area covers a wide spectrum of geologic formations producing both oil and natural gas. Although the Mid-Continent was the site of some of the earliest oil and gas discoveries in the United States, the area continues to offer exploration potential. New technologies such as 3-D seismic are enabling Devon to study complex geologic environments and identify new exploratory prospects. Nuclear magnetic resonance logging is being applied by Devon in the Carthage-Bethany area of east Texas. Devon acquired its position in Carthage-Bethany in the PennzEnergy merger. Previously bypassed reserves are being discovered in wells in Carthage-Bethany through application of this new reserve evaluation technology. SOUTHERN DIVISION PROPERTIES ONSHORE. Devon's Gulf Coast area includes lands in south Texas and south Louisiana. In south Texas, where exploration for oil and gas is accelerating, Devon has 3-D seismic data covering its major acreage positions. This acreage is prospective for production in the Charco Lobo, Middle Wilcox and Frio-Vicksburg formations. The Company's exploration efforts in south Louisiana are focused on natural gas prospects in the lower, mid and upper Miocene age formations. The Gulf Coast area provides ready access to pipelines and production facilities. Natural gas from the Gulf Coast is typically priced at a premium to other U.S. producing areas. OFFSHORE. The offshore Gulf of Mexico is a prolific producing area that provides approximately 25% of the natural gas produced in the United States. With a substantial infrastructure of platforms and production facilities, Devon is one of the largest operators on the shallow-water "shelf." Producing gas wells on the shelf are known for providing high initial flow rates and quick investment returns. As deep water drilling and production technology improves, operators are moving into the waters beyond the shelf. Technology now exists to drill and produce oil at water depths of 3,000 feet and deeper. The deep water Gulf of Mexico is believed to hold some of North America's largest remaining undiscovered oil and gas reserves. Devon has a substantial inventory of exploration acreage in the deeper Gulf waters. 17 18 CANADIAN PROPERTIES Western Canada is Devon's largest production area. The Western Canadian Sedimentary Basin is a vast geologic feature encompassing portions of British Columbia, Alberta, Saskatchewan and Manitoba. The basin feature forms a wedge-shaped depression that tapers from a maximum thickness of 17,000 feet on the western and southern margins to a zero edge along the northeast. Devon's properties in Canada range from shallow oil and natural gas production in northern Alberta to deep, long-lived gas reservoirs in the Foothills area near the Alberta/British Columbia border. Approximately 2.2 million net acres of undeveloped leasehold in the Western Canadian Sedimentary Basin provide Devon with numerous exploration and development opportunities. INTERNATIONAL DIVISION PROPERTIES Most of Devon's proved reserves that lie outside North America are located under the Caspian Sea, offshore Azerbaijan, part of the former Soviet Union. The Caspian Basin is considered to hold some of the world's last known major undeveloped hydrocarbon reserves. Devon holds a 4.8% carried interest in the Azeri-Chirag-Gunashli joint development area. This area is estimated to contain five billion barrels of crude oil. Devon expects significant production from its interest in Azerbaijan to begin sometime between 2005 and 2010. Devon also has international operations in Brazil, Egypt, Qatar and Venezuela. In Egypt, Devon expects to begin producing oil in the second half of 2000 from a 1999 discovery. Although Devon currently produces a modest amount of oil in Venezuela, we do not expect to remain active in that country. 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 in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). 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. LEGAL PROCEEDINGS Ramco Dispute In October 1995, subsidiaries of Devon acquired in the PennzEnergy merger filed an action, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States District Court for the Southern District of Texas, Houston Division, against Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively "Ramco"). The underlying dispute involves Ramco's asserted claim to an interest in the Karabakh prospect, an oil and gas field located in the territorial waters of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the litigation, the operator of the Karabakh prospect determined that the hydrocarbon accumulation tested by three exploratory wells was not commercial. The federal suit sought to compel Ramco to arbitrate certain disputes that have arisen between it and 18 19 the Devon plaintiffs pursuant to the Federal Arbitration Act and the Convention on the Recognition and Enforcement of Foreign Arbitral Awards. After the filing of the federal action, the Devon plaintiffs filed an Original Petition for Declaration Relief in the 281st Judicial District Court of Harris County, Texas. The state suit, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is expressly conditioned upon a determination in the federal suit that the disputes between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a declaration that the Devon plaintiffs have not breached any agreements with Ramco, and do not owe and/or have not breached any fiduciary or other legal duty to Ramco including, without limitation, a duty of good faith and fair dealing. In November 1995, Ramco asserted a counterclaim in the state court action, asserting breach of contract and breach of fiduciary duties. The counterclaim seeks a declaratory judgment granting Ramco a participation interest in the Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees, court costs and other unspecified relief. The judge in the federal suit granted in part the plaintiffs' motion to compel arbitration and ordered arbitration to be held in New York, New York. The United States Court of Appeals for the Fifth Circuit generally affirmed the ruling of the judge in the federal suit and the Devon plaintiffs initiated arbitration. The parties have been engaged in settlement discussions and the selection of arbitrators has been suspended by agreement of the parties pending the outcome of the settlement discussions. Royalty Matters More than 30 oil companies, including Devon as a result of the PennzEnergy merger, are involved in disputes in which it is alleged that the oil companies and related parties have underpaid holders of royalty interests, overriding royalty interests and working interests in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana. Certain parties to the federal litigation have entered into a global settlement agreement which provides for a conditional nationwide settlement, subject to opt-outs, of the crude oil royalty, overriding royalty and working interest claims of all members of the settlement class, including claims in the federal litigation and in numerous other individual and class action cases pending throughout the United States. The federal court held a fairness hearing April 5, 1999, and the settlement was approved. The Amended Final Judgment was entered September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon is a party to the settlement agreement, which explicitly refutes an admission of liability, but was entered into to avoid expensive and protracted litigation. Also, pending is a separate suit in federal court in Texas alleging that more than 30 major oil companies, including Devon as a result of the PennzEnergy merger, underpaid royalties to the United States in connection with crude oil produced from United States owned and/or controlled lands since 1986. The claims were filed by private litigants under the federal False Claims Act, and after investigation, the United States served notice of its intent to intervene as to certain defendants. Devon has reached an agreement in principle with the United States and the private litigants to settle the claims made in the case. Devon believes that it has acted reasonably and paid royalties in good faith, but has entered into the settlement agreement, which explicitly refutes an admission of liability, to avoid expensive and protracted litigation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such settlement of the royalty matters. 19 20 Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge as of March 24, 2000, 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 20 21 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS MARKET PRICE Devon's common stock has been traded on the American Stock Exchange (the "AMEX") since September 29, 1988. Prior to September 29, 1988, Devon's common stock was privately held. Commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange ("TSE") under the symbol NSX. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon's wholly-owned subsidiary, Northstar, they qualify as a domestic Canadian investment for Canadian institutional shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon at the holder's option. The following table sets forth the high and low sales prices for Devon common stock and exchangeable shares as reported by the AMEX and TSE for the periods indicated.
American Stock Exchange The Toronto Stock Exchange ----------------------------- ----------------------------- Average Average High Low Daily High Low Daily (US$) (US$) Volume (CN$) (CN$) Volume ----- ----- -------- ------ ----- ------- 1998: Quarter Ended March 31, 1998 41.13 32.88 90,867 Quarter Ended June 30, 1998 40.50 32.63 97,527 Quarter Ended September 30, 1998 36.63 26.13 158,909 Quarter Ended December 31, 1998 * 36.69 27.75 140,888 45.45 42.75 1,220 1999: Quarter Ended March 31, 1999 31.75 20.13 233,954 48.00 30.40 4,240 Quarter Ended June 30, 1999 37.44 25.94 225,938 54.85 39.60 15,457 Quarter Ended September 30, 1999 44.94 33.00 624,356 65.75 51.30 11,650 Quarter Ended December 31, 1999 42.00 29.50 486,409 61.60 43.45 3,108 2000: Quarter Ended March 31, 2000 45.25 31.69 380,690 65.25 45.65 13,493 (through March 15, 2000)
* Trading of the exchangeable shares on the TSE commenced on December 15, 1998. DIVIDENDS Devon commenced the payment of regular quarterly cash dividends on its common stock on June 30, 1993, in the amount of $0.03 per share. Effective December 31, 1996, Devon increased its quarterly dividend payment to $0.05 per share. Devon anticipates continuing to pay regular quarterly dividends in the foreseeable future. Dividends are also paid on the exchangeable shares at the same rate and on the same dates as dividends paid on the common stock. On March 15, 2000, there were 13,796 holders of record of Devon common stock and 48 holders of record for the exchangeable shares. 21 22 ITEM 6. SELECTED FINANCIAL DATA The following selected financial information (not covered by the independent auditors' reports) should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and the consolidated financial statements and the notes thereto included in "Item 8. Financial Statements and Supplementary Data." Note 2 to the consolidated financial statements included in Item 8 of this report contains information on the 1999 merger with PennzEnergy and the 1998 combination of Devon and Northstar, as well as unaudited pro forma financial data for the years 1999 and 1998.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 1999 1998 1997 1996 1995 --------- --------- --------- --------- --------- (THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS) OPERATING RESULTS Oil sales $ 273,234 143,624 207,725 136,023 115,606 Gas sales 385,925 209,344 219,459 101,443 71,194 NGLs sales 56,344 16,692 24,920 19,299 9,091 Other revenue 18,996 17,848 47,555 34,570 14,252 --------- --------- --------- --------- --------- Total revenues 734,499 387,508 499,659 291,335 210,143 --------- --------- --------- --------- --------- Lease operating expenses 166,848 113,484 100,897 58,734 51,724 Production taxes 23,055 13,916 19,227 10,880 7,052 Depreciation, depletion and amortization of property and equipment 254,275 123,844 169,108 70,307 73,440 Amortization of goodwill 16,111 -- -- -- -- General and administrative expenses 53,845 23,554 24,381 15,111 14,906 Northstar Combination expenses -- 13,149 -- -- -- Interest expense 66,913 22,632 18,788 12,662 10,885 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860 199 307 Distributions on preferred securities of subsidiary trust 6,884 9,717 9,717 4,753 -- Reduction of carrying value of oil and gas properties -- 126,900 625,514 -- 97,061 --------- --------- --------- --------- --------- Total costs and expenses 574,777 463,300 973,492 172,646 255,375 --------- --------- --------- --------- --------- Earnings (loss) before income taxes 159,722 (75,792) (473,833) 118,689 (45,232) Income tax expense (benefit): Current 24,656 7,687 26,857 7,834 5,292 Deferred 40,510 (23,194) (200,699) 43,252 (24,631) --------- --------- --------- --------- --------- Total 65,166 (15,507) (173,842) 51,086 (19,339) --------- --------- --------- --------- --------- Net earnings (loss) $ 94,556 (60,285) (299,991) 67,603 (25,893) ========= ========= ========= ========= ========= Net earnings (loss) applicable to common stock $ 90,905 (60,285) (299,991) 67,603 (25,893) ========= ========= ========= ========= ========= Net earnings (loss) per share: Basic $ 1.51 (1.25) (6.38) 2.06 (0.80) Diluted $ 1.46 (1.25) (6.38) 1.99 (0.80) Cash dividends per common share(1) $ 0.20 0.15 0.14 0.15 0.14 Weighted average common shares outstanding - basic 60,015 48,376 47,040 32,812 32,473 Ratio of earnings to combined fixed charges and preferred stock dividends(2) 3.37 N/A N/A 7.59 N/A
22 23
DECEMBER 31, ------------------------------------------------------------- 1999 1998 1997 1996 1995 ---------- --------- --------- --------- --------- (THOUSANDS) BALANCE SHEET DATA Total assets $4,623,160 1,226,356 1,248,986 1,183,290 715,510 Debentures exchangeable into shares of Chevron Corporation common stock $ 760,313 -- -- -- -- Other long-term debt $1,026,808 405,271 305,337 83,000 220,137 Convertible preferred securities of subsidiary trust $ -- 149,500 149,500 149,500 -- Stockholders' equity $2,025,520 522,963 596,546 678,772 394,647
YEAR ENDED DECEMBER 31, ------------------------------------------------------------- 1999 1998 1997 1996 1995 --------- --------- --------- --------- --------- (THOUSANDS, EXCEPT PER UNIT DATA) CASH FLOW DATA Net cash provided by operating activities $ 205,628 191,571 235,056 144,248 122,136 Net cash used in investing activities $(253,717) (271,960) (147,583) (243,451) (251,571) Net cash provided by (used in) financing activities $ 195,398 57,618 (77,141) 96,420 125,312 Modified EBITDA(3,5) $ 490,751 223,405 355,154 206,610 136,461 Cash margin(4,5) $ 392,298 183,369 299,792 181,361 120,284 PRODUCTION, PRICE AND OTHER DATA Production: Oil (MBbls) 15,416 11,903 11,783 6,780 7,130 Gas (MMcf) 198,457 133,065 121,810 62,186 58,234 NGLs (MBbls) 4,022 1,939 1,891 1,255 831 MBoe(6) 52,514 36,020 33,976 18,399 17,666 Average prices: Oil (Per Bbl) $ 17.72 12.07 17.63 20.06 16.21 Gas (Per Mcf) $ 1.94 1.57 1.80 1.63 1.22 NGLs (Per Bbl) $ 14.01 8.61 13.18 15.38 10.94 Per Boe(6) $ 13.62 10.26 13.31 13.96 11.09 Costs per Boe: Operating costs $ 3.62 3.54 3.54 3.78 3.33 Depreciation, depletion and amortization of oil and gas properties $ 4.65 3.32 4.86 3.69 4.04 General and administrative expenses $ 1.03 0.65 0.72 0.82 0.84
- - - - - - - - --------------------------- (1) Cash dividends per share are presented based on the combined amount of dividends paid by both Devon and Northstar in each year. The dividends per share are also based on the number of shares outstanding in each year assuming the Northstar Combination had been consummated as of the beginning of the earliest year presented. Northstar did not pay any dividends in 1997, or in 1998 prior to the closing of the Northstar Combination. Also, Northstar's dividends paid in 1996 and 1995 were at rates per share that were different from the rates paid by Devon in those years. Because of these facts, the cash dividends per share presented for 1995 through 1998 are not representative of the actual amounts paid by Devon on an historical basis. For the years 1998, 1997, 1996 and 1995, Devon's historical cash dividends per share were $0.20, $0.20, $0.14 and $0.12, respectively. (2) For purposes of calculating the ratio of earnings to combined fixed charges and preferred stock dividends, (i) earnings consist of earnings before income taxes, plus fixed charges; (ii) fixed charges consist of interest expense, deferred effect of changes in foreign currency exchange rate on long-term debt, distributions on preferred securities of subsidiary trust, amortization of costs relating to indebtedness and the preferred securities of subsidiary trust, and one-third of rental 23 24 expense estimated to be attributable to interest; and (iii) preferred stock dividends consist of the amount of pre-tax earnings required to pay dividends on the outstanding preferred stock. For the years 1998, 1997 and 1995, earnings were insufficient to cover fixed charges by $75.8 million, $473.8 million and $45.2 million, respectively. (3) Modified EBITDA represents earnings before interest (including deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt, and distributions on preferred securities of subsidiary trust), taxes, depreciation, depletion and amortization and reduction of carrying value of oil and gas properties. (4) "Cash margin" equals total revenues less cash expenses. Cash expenses are all expenses other than the non-cash expenses of depreciation, depletion and amortization, deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt, reduction of carrying value of oil and gas properties and deferred income tax expense. Cash margin measures the net cash which is generated by a company's operations during a given period, without regard to the period such cash is actually physically received or spent by the company. This margin ignores the non-operational effect on a company's "net cash provided by operating activities", as measured by generally accepted accounting principles, from a company's activities as an operator of oil and gas wells. Such activities produce net increases or decreases in temporary cash funds held by the operator which have no effect on net earnings of the company. (5) Modified EBITDA is presented because it is commonly accepted in the oil and gas industry as a financial indicator of a company's ability to service or incur debt. Cash margin is presented because it is commonly accepted in the oil and gas industry as a financial indicator of a company's ability to fund capital expenditures or service debt. Modified EBITDA and cash margin are also presented because investors routinely request such information. Management interprets the trends of modified EBITDA and cash margin in a similar manner as trends in net earnings. Modified EBITDA and cash margin should be used as supplements to, and not as substitutes for, net earnings and net cash provided by operating activities determined in accordance with generally accepted accounting principles as measures of Devon's profitability or liquidity. There may be operational or financial demands and requirements that reduce management's discretion over the use of modified EBITDA and cash margin. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." Modified EBITDA and cash margin may not be comparable to similarly titled measures used by other companies. (6) Gas volumes are converted to Boe or MBoe 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. The respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content. 24 25 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 1997 through 1999. Reference is made to "Item 6. Selected Financial Data" and "Item 8. Financial Statements and Supplementary Data." OVERVIEW On August 17, 1999, Devon and PennzEnergy Company ("PennzEnergy") closed their merger that was previously announced on May 20, 1999. In the merger, Devon issued approximately 21.5 million shares of common stock and assumed $1.6 billion of long-term debt and $0.7 billion of other liabilities. The merger added 396 million Boe of reserves, 13 million net acres of undeveloped leasehold and $3.2 billion of assets to Devon's balance sheet. This significantly expanded the scope of Devon's operations and moved Devon into the top ten of all U.S.-based independent oil and gas producers. The PennzEnergy merger was accounted for under the purchase method of accounting for business combinations. Therefore, Devon's 1999 results do not include any effect of PennzEnergy's operations prior to August 17, 1999. The PennzEnergy merger was completed less than a year after Devon's merger with Northstar Energy Corporation ("Northstar"). The December 10, 1998, combination of Devon and Northstar (the "Northstar Combination") added 115 million Boe of proved reserves and 1.8 million undeveloped acres, all in Canada. The Northstar Combination was accounted for under the pooling-of-interests method of accounting for business combinations. Accordingly, Devon's results for 1998 and prior years include the results of both Devon and Northstar as if the two had always been combined. In addition to the two mergers, Devon's exploration, drilling and development efforts have also been significant contributors to Devon's growth over the last three years. Excluding the pooled results of Northstar prior to December 1998, Devon has spent approximately $492 million in its exploration, drilling and development efforts from 1997 through 1999. These costs included drilling 1,154 wells, of which 1,065 were completed as producers. The impact of the mergers and drilling activities include the following changes from 1997 to 1999. (The following changes are calculated using 1997's results without combining Northstar's results, and the 1999 results include the effects of the added PennzEnergy operations for only the last 4 1/2 months of the year.) o Combined oil, gas and NGLs production increased 32.3 million Boe, or 160%. o Combined oil, gas and NGLs revenues increased $409.8 million, or 134%, during a period when the average combined price of oil, gas and NGLs fell by $1.53 per Boe, or 10%. o Net cash provided by operating activities increased $36.9 million, or 22%. Cash margin increased $210.9 million, or 116%. 25 26 o Net earnings increased $19.3 million, or 26%. o Production and operating expenses per Boe dropped $0.52 per Boe, or 19%. o Depreciation, depletion and amortization of oil and gas properties per Boe increased $0.58 per Boe, or 14%. o General and administrative expenses per Boe increased $0.39 per Boe, or 61%. However, Devon expects to eliminate a substantial part of this increase in costs per Boe in 2000 due to the termination at the end of 1999 of certain commitments inherited as part of the PennzEnergy merger. During 1999, Devon marked its eleventh anniversary as a public company. While Devon has consistently increased production over this eleven-year period, volatility in oil and gas prices has resulted in considerable variability in earnings and cash flows. Prices for oil, natural 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 world-wide economic growth, weather and other factors that are beyond Devon's control. Devon's future earnings and cash flows will continue to depend on market conditions. Like all oil and gas production companies, Devon faces the challenge of natural production decline. As virgin pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas production company depletes part of its asset base with each unit of oil or gas it produces. Historically, Devon has been able to overcome this natural decline by adding, through drilling and acquisitions, more reserves than it produces. Devon's future growth, if any, will depend on its ability to continue to add reserves in excess of production. Because oil and gas prices are influenced by many factors outside of its control, Devon's management has focused its efforts on increasing oil and gas reserves and production and controlling expenses. Over its eleven year history as a public company, Devon has been able to significantly reduce its operating costs per unit of production. Devon's future earnings and cash flows are dependent on its ability to continue to contain operating costs at levels that allow for profitable production of its oil and gas reserves. RESULTS OF OPERATIONS Devon's total revenues have risen from $499.7 million in 1997 to $734.5 million in 1999. In each of these three years, oil, gas and NGLs sales accounted for over 90% of total revenues. Changes in oil, gas and NGLs production, prices and revenues from 1997 to 1999 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.) 26 27
TOTAL ------------------------------------------------------------- YEAR ENDED DECEMBER 31, ------------------------------------------------------------- 1999 1998 1999 VS 1998 1998 VS 1997 1997 ---------- ------- --------- ------- -------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls) ...................... 15,416 +30% 11,903 +1% 11,783 Gas (MMcf) ....................... 198,457 +49% 133,065 +9% 121,810 NGLs (MBbls) ..................... 4,022 +107% 1,939 +3% 1,891 Oil, gas and NGLs (MBoe) ......... 52,514 +46% 36,020 +6% 33,976 REVENUES Per Unit of Production: Oil (per Bbl) .................. $ 17.72 +47% 12.07 (32)% 17.63 Gas (per Mcf) .................. $ 1.94 +24% 1.57 (13)% 1.80 NGLs (per Bbl) ................. $ 14.01 +63% 8.61 (35)% 13.18 Oil, gas and NGLs (per Boe) .... $ 13.62 +33% 10.26 (23)% 13.31 Absolute: Oil ............................ $ 273,234 +90% 143,624 (31)% 207,725 Gas ............................ $ 385,925 +84% 209,344 (5)% 219,459 NGLs ........................... $ 56,344 +238% 16,692 (33)% 24,920 ---------- --------- --------- Oil, gas and NGLs .............. $ 715,503 +94% 369,660 (18)% 452,104 ========== ========= =========
DOMESTIC -------------------------------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1999 1998 1999 VS 1998 1998 VS 1997 1997 ---------- ------- --------- ------- -------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls) ...................... 9,791 +73% 5,646 (7)% 6,055 Gas (MMcf) ....................... 124,896 +90% 65,907 +8 % 61,015 NGLs (MBbls) ..................... 3,322 +142% 1,373 (6)% 1,468 Oil, gas and NGLs (MBoe) ......... 33,929 +88% 18,004 +2 % 17,692 REVENUES Per Unit of Production: Oil (per Bbl) .................. $ 19.83 +59% 12.45 (35)% 19.08 Gas (per Mcf) .................. $ 2.23 +16% 1.92 (16)% 2.28 NGLs (per Bbl) ................. $ 13.94 +59% 8.79 (33)% 13.18 Oil, gas and NGLs (per Boe) .... $ 15.31 +32% 11.59 (25)% 15.48 Absolute: Oil ............................ $ 194,162 +176% 70,286 (39)% 115,504 Gas ............................ $ 279,030 +121% 126,273 (9)% 139,018 NGLs ........................... $ 46,310 +284% 12,071 (38)% 19,338 ---------- --------- -------- Oil, gas and NGLs .............. $ 519,502 +149% 208,630 (24)% 273,860 ========== ========= ========
27 28
CANADA ------------------------------------------------------------ YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 1999 1998 1999 VS 1998 1998 VS 1997 1997 ---------- ------- --------- --------- --------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls) ...................... 5,178 (17)% 6,257 + 9 % 5,728 Gas (MMcf) ....................... 73,561 +10% 67,158 +10 % 60,795 NGLs (MBbls) ..................... 700 +24% 566 +34 % 423 Oil, gas and NGLs (MBoe) ......... 18,138 +1% 18,016 +11 % 16,284 REVENUES Per Unit of Production: Oil (per Bbl) .................. $ 14.71 +26% 11.72 (27)% 16.10 Gas (per Mcf) .................. $ 1.45 +17% 1.24 (6)% 1.32 NGLs (per Bbl) ................. $ 14.33 +76% 8.16 (38)% 13.20 Oil, gas and NGLs (per Boe) .... $ 10.65 +19% 8.94 (18)% 10.95 Absolute: Oil ............................ $ 76,171 +4% 73,338 (20)% 92,221 Gas ............................ $ 106,895 +29% 83,071 +3 % 80,441 NGLs ........................... $ 10,034 +117% 4,621 (17)% 5,582 ---------- --------- --------- Oil, gas and NGLs .............. $ 193,100 +20% 161,030 (10)% 178,244 ========== ========= =========
In addition to the volumes included in the prior tables for domestic and Canadian production, in the last 4 1/2 months of 1999 Devon also produced 424,000 barrels of oil in Venezuela and 23,000 barrels of oil in Azerbaijan. The oil revenues generated by this production were $2.9 million. This production was added by the PennzEnergy merger. OIL REVENUES 1999 vs. 1998 Oil revenues increased $129.6 million in 1999. Oil revenues increased $87.2 million due to a $5.65 per barrel increase in the average price of oil in 1999. An increase in 1999's production of 3.5 million barrels caused oil revenues to increase by $42.4 million. The PennzEnergy merger added 5.3 million barrels of production during the last 4 1/2 months of 1999. This increase was partially offset by a 1.8 million barrel decline in 1999 production from Devon's other properties. The disposition of certain Canadian producing properties during 1998, the deferral of some oil-oriented projects, natural decline, and the effect of some properties that were shut-in earlier in 1999 due to low prices were the primary reasons for this production decline. 1998 vs. 1997 Oil revenues decreased $64.1 million in 1998. An average price decline of $5.56 per barrel reduced revenues by $66.2 million. This was slightly offset by $2.1 million of revenues added by production gains of 120,000 barrels. GAS REVENUES 1999 vs. 1998 Gas revenues increased $176.6 million in 1999. A 65.4 Bcf increase in production in 1999 added $102.9 million of gas revenues compared to 1998. A $0.37 per Mcf increase in the average gas price in 1999, contributed $73.7 million of the increase in gas revenues. The largest contributor to the 1999 production increase was production added by the PennzEnergy merger. The PennzEnergy properties added 55.5 Bcf of production during the 4 1/2 months following the merger. A 6.4 Bcf increase in Devon's Canadian gas production also 28 29 contributed to the increase in 1999 gas production. The Canadian gas production increase was primarily the result of two 1998 acquisitions. Gas production from Devon's historical domestic properties also increased in 1999. This was due to a 3.9 Bcf increase in production from Devon's San Juan Basin coal seam gas properties. These properties produced 23.8 Bcf of gas in 1999 compared to 19.9 Bcf in 1998. This increase was largely the result of a program of mechanical improvements implemented at the Northeast Blanco Unit coal seam gas property during 1998. 1998 vs. 1997 Gas revenues decreased $10.1 million in 1998. An average price decline of $0.23 per Mcf reduced revenues by $30.4 million. This was partially offset by higher production in 1998. A production increase of 11.3 Bcf in 1998 added gas revenues of $20.3 million. The San Juan Basin coal seam gas properties produced 19.9 Bcf in 1998 compared to 17.6 Bcf in 1997. The majority of the production gains realized in 1998 were the result of improvements at the Northeast Blanco Unit property. NGLS REVENUES 1999 vs. 1998 NGLs revenues increased $39.7 million in 1999. An increase in 1999's average price of $5.40 per barrel caused NGLs revenues to increase $21.7 million. A production increase of 2.1 million barrels in 1999 caused revenues to increase $18.0 million. Production from the PennzEnergy properties for the last 4 1/2 months of 1999 accounted for 1.7 million barrels of the 1999 increase. 1998 vs. 1997 NGLs revenues decreased $8.2 million in 1998. An average price decline of $4.57 per barrel caused revenues to drop by $8.9 million. This decline was slightly offset by production increases of 48,000 barrels. Such production gains added $0.7 million of revenues in 1998. OTHER REVENUES 1999 vs. 1998 Other revenues increased $1.1 million in 1999. Other revenues in 1999 included $6.7 million of dividend income in the last 4 1/2 months of the year from the 7.1 million shares of Chevron Corporation common stock acquired by Devon in the PennzEnergy merger. This dividend income, along with increases in 1999's revenues from third-party gas processing activities and interest income, caused other revenues to increase by $9.9 million. These increases were partially offset by $8.8 million of one-time revenues recognized by Northstar in 1998 from terminations of certain management agreements and gas contracts. 1998 vs. 1997 Other revenues decreased $29.7 million in 1998. This decrease was primarily due to Northstar's $29.4 million of gains from asset sales in 1997 which did not recur in 1998. 29 30 EXPENSES The details of the changes in pre-tax expenses between 1997 and 1999 are shown in the table below.
YEAR ENDED DECEMBER 31, ------------------------------------------------------ 1999 1998 1999 VS 1998 1998 VS 1997 1997 ---------- ------- --------- --------- ------- (ABSOLUTE AMOUNTS IN THOUSANDS) Absolute: Production and operating expenses: Lease operating expenses ............................ $ 166,848 +47% 113,484 +12% 100,897 Production taxes .................................... 23,055 +66% 13,916 (28)% 19,227 Depreciation, depletion and amortization of oil and gas properties .............................. 244,517 +104% 119,719 (27)% 164,977 Amortization of goodwill ............................. 16,111 N/A -- -- -- ---------- -------- -------- Subtotal .......................................... 450,531 +82% 247,119 -13% 285,101 Depreciation and amortization of non-oil and gas properties ...................................... 9,758 +137% 4,125 -- 4,131 General and administrative expenses ................... 53,845 +129% 23,554 (3)% 24,381 Northstar Combination expenses ........................ -- (100)% 13,149 N/A -- Interest expense ...................................... 66,913 +196% 22,632 +20% 18,788 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt ........ (13,154) N/A 16,104 +175% 5,860 Distributions on preferred securities of subsidiary trust .................................... 6,884 (29)% 9,717 -- 9,717 Reduction of carrying value of oil and gas properties .......................................... -- (100)% 126,900 (80)% 625,514 ---------- -------- -------- Total ............................................. $ 574,777 +24% 463,300 (52)% 973,492 ========== ======== ======== Per Boe: Production and operating expenses: Lease operating expenses ............................ $ 3.18 +1% 3.15 +6% 2.97 Production taxes .................................... 0.44 +13% 0.39 (32)% 0.57 Depreciation, depletion and amortization of oil and gas properties .............................. 4.65 +40% 3.32 (32)% 4.86 Amortization of goodwill .............................. 0.31 N/A -- -- -- ---------- -------- --------- Subtotal .......................................... 8.58 +25% 6.86 (18)% 8.40 Depreciation and amortization of non-oil and gas properties (1) .................................. 0.19 +58% 0.12 -- 0.12 General and administrative expenses (1) ............... 1.03 +58% 0.65 (10)% 0.72 Northstar Combination expenses (1) .................... -- (100)% 0.36 N/A -- Interest expense (1) .................................. 1.27 +102% 0.63 +15% 0.55 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (1) .... (0.25) N/A 0.45 +165% 0.17 Distributions on preferred securities of subsidiary trust (1) ................................ 0.13 (52)% 0.27 (4)% 0.28 Reduction of carrying value of oil and gas properties (1) ...................................... -- (100)% 3.52 (81)% 18.41 ---------- --------- --------- Total .............................................. $ 10.95 (15)% 12.86 (55)% 28.65 ========== ========= =========
- - - - - - - - -------------------- (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. 30 31 PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expenses between 1997 and 1999 are shown in the table below.
TOTAL -------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------- 1999 1998 1999 VS 1998 1998 VS 1997 1997 ------------ ------------ ------------ ------------ ------------ (ABSOLUTE AMOUNTS IN THOUSANDS) Absolute: Recurring lease operating expenses $ 160,166 +49% 107,554 +11% 96,738 Well workover expenses 6,682 +13% 5,930 +43% 4,159 Production taxes 23,055 +66% 13,916 (28)% 19,227 ------------ ------------ ------------ Total production and operating expenses $ 189,903 +49% 127,400 +6% 120,124 ============ ============ ============ Per Boe: Recurring lease operating expenses $ 3.05 +2% 2.99 +5% 2.85 Well workover expenses 0.13 (19)% 0.16 +33% 0.12 Production taxes 0.44 +13% 0.39 (32)% 0.57 ------------ ------------ ------------ Total production and operating expenses $ 3.62 +2% 3.54 -- 3.54 ============ ============ ============
DOMESTIC YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------- 1999 1998 1999 VS 1998 1998 VS 1997 1997 ------------ ------------ ------------ ------------ ------------ (ABSOLUTE AMOUNTS IN THOUSANDS) Absolute: Recurring lease operating expenses $ 109,775 +80% 60,920 +11% 54,969 Well workover expenses 5,742 +23% 4,654 +48% 3,143 Production taxes 21,692 +77% 12,255 (31)% 17,646 ------------ ------------ ------------ Total production and operating expenses $ 137,209 +76% 77,829 +3% 75,758 ============ ============ ============ Per Boe: Recurring lease operating expenses $ 3.23 (4)% 3.38 +9% 3.10 Well workover expenses 0.17 (35)% 0.26 +44% 0.18 Production taxes 0.64 (6)% 0.68 (32)% 1.00 ------------ ------------ ------------ Total production and operating expenses $ 4.04 (6)% 4.32 +1% 4.28 ============ ============ ============
CANADA -------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------- 1999 1998 1999 VS 1998 1998 VS 1997 1997 ------------ ------------ ------------ ------------ ------------ (ABSOLUTE AMOUNTS IN THOUSANDS) Absolute: Recurring lease operating expenses $ 48,891 +5% 46,634 +12% 41,769 Well workover expenses 940 (26)% 1,276 +26% 1,016 Production taxes 1,363 (18)% 1,661 +5% 1,581 ------------ ------------ ------------ Total production and operating expenses $ 51,194 +3% 49,571 +12% 44,366 ============ ============ ============ Per Boe: Recurring lease operating expenses $ 2.70 +4% 2.59 +1% 2.56 Well workover expenses 0.05 (29)% 0.07 +17% 0.06 Production taxes 0.07 (22)% 0.09 (10)% 0.10 ------------ ------------ ------------ Total production and operating expenses $ 2.82 +3% 2.75 +1% 2.72 ============ ============ ============
31 32 In addition to the expenses included in the prior tables for domestic and Canadian operations, in the last 4 1/2 months of 1999 Devon also incurred $1.5 million of recurring lease operating expenses on its properties outside North America. These expenses were related to properties added by the PennzEnergy merger. 1999 vs. 1998 Recurring lease operating expenses increased $52.6 million in 1999. Domestic expenses increased $48.9 million in 1999 due to $55.8 million of expenses for the last 4 1/2 months of the year from the PennzEnergy properties. Other than the added costs from the PennzEnergy properties, recurring expenses on Devon's other domestic properties dropped $6.9 million in 1999. Efficiencies achieved in certain of Devon's oil producing properties contributed most of this cost reduction. The majority of Devon's production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes paid are based on a fixed percentage of revenues. Therefore, the 149% increase in domestic oil, gas and NGLs revenues was the primary cause of the 77% increase in domestic production taxes. Production taxes did not increase proportionately to the increase in revenues. This was primarily due to the addition in 1999 of gas revenues from offshore Gulf of Mexico properties acquired in the PennzEnergy merger. Revenues generated from such offshore properties do not incur state production taxes. 1998 vs. 1997 Recurring lease operating expenses increased $10.8 million, or 11%, in 1998. The primary causes of this increase were the addition of wells drilled or acquired during 1998 and the effect of having a full year of operations in 1998 from certain Canadian properties acquired in March 1997. Recurring expenses increased $0.14 per Boe, or 5%, in 1998. This increase was predominantly caused by a 9% increase in costs per Boe on the domestic properties. The operating expenses of the domestic wells drilled during the year raised the overall average costs per Boe in the U.S. As previously stated, most of the U.S. production taxes paid are based on a fixed percentage of revenues. Therefore, the 24% drop in 1998 domestic oil, gas and NGLs revenues was the primary cause of the 31% decrease in domestic production taxes. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") Devon's largest recurring non-cash expense is 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 in those reserves including estimated future development costs (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. 1999 vs. 1998 Oil and gas property related DD&A increased $124.8 million, or 104%, in 1999. An increase in the consolidated DD&A rate from $3.32 per Boe in 1998 to $4.65 per Boe in 1999 caused DD&A expense to increase $70.0 million. The 1999 rate of $4.65 per Boe was a 32 33 blended rate of before and after the PennzEnergy merger. The consolidated rate going into 2000 was $5.41 per Boe. Oil and gas property related DD&A expense increased $54.8 million due to the 46% increase in oil, gas and NGLs production in 1999. Non-oil and gas property DD&A increased $5.6 million in 1999 compared to 1998. Depreciation of the non-oil and gas properties acquired in the PennzEnergy merger and depreciation of Devon's new Wyoming gas pipeline and gathering system, accounted for the increase in 1999's expense. 1998 vs. 1997 Oil and gas property related DD&A decreased $45.3 million, or 27%, in 1998. A 32% drop in the consolidated DD&A rate per Boe from $4.86 in 1997 to $3.32 in 1998 reduced 1998's DD&A expense by $55.2 million. This decrease was partially offset by $9.9 million of increased expense caused by the 6% increase in combined oil, gas and NGLs production in 1998. The $625.5 million reduction in the carrying value of Canadian oil and gas properties recorded at the end of 1997 was the primary cause of the drop in the 1998 DD&A rate. AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger, Devon recorded $338.9 million of goodwill. The goodwill recorded was allocated $302.0 million to domestic properties and $26.9 million to international properties. The goodwill is being amortized using the units-of-production method. Substantially all of the $16.1 million of amortization recognized in 1999 was related to the domestic balance. GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full cost method of accounting. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property's life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. See following table for a summary of G&A expenses by component.
TOTAL ---------------------------------------------------- YEAR ENDED DECEMBER 31, ---------------------------------------------------- 1999 1998 1999 VS 1998 1998 VS 1997 1997 ------- ------- ------- ------- ------- (IN THOUSANDS) Gross G&A ........................... $94,341 +85% 50,989 +7% 47,832 Capitalized G&A....................... (18,678) +94% (9,612) +27% (7,575) Reimbursed G&A........................ (21,818) +22% (17,823) +12% (15,876) ------- ------ ------- Net G&A........................... $53,845 +129% 23,554 (3)% 24,381 ======= ====== =======
1999 vs. 1998 Net G&A increased $30.3 million in 1999. Gross G&A increased $43.4 million in 1999. Included in the increase in gross expenses were $36.7 million of expenses related to 4 1/2 months of the PennzEnergy operations. The PennzEnergy amounts included $4.4 million of nonrecurring retention bonuses paid to certain PennzEnergy employees as an inducement to remain with Devon for two months following the merger closing. 33 34 G&A was lowered $9.1 million due to an increase in the amount capitalized as part of oil and gas properties. The 1999 amount capitalized included $5.5 million related to the PennzEnergy operations for the last 4 1/2 months of the year. G&A was also reduced by a $4.0 million increase in the amount of reimbursements on operated properties. The 1999 reimbursements received from the PennzEnergy properties were $6.0 million. 1998 vs. 1997 Net G&A decreased $0.8 million in 1998. Gross G&A increased $3.1 million in 1998. However, this increase was more than offset by increases in the amount of G&A capitalized and reimbursed in 1998. G&A was lowered $2.0 million due to an increase in the amount capitalized as part of oil and gas properties. G&A was also reduced by a $1.9 million increase in the amount of reimbursements on operated properties. NORTHSTAR COMBINATION EXPENSES Approximately $13.1 million of expenses were incurred in 1998 in connection with the Northstar Combination. These expenses consisted primarily of investment bankers' fees, legal fees and costs of printing and distributing the proxy statement to shareholders. The pooling-of-interests method of accounting for business combinations requires such costs to be expensed as opposed to capitalized as costs of the transaction. INTEREST EXPENSE 1999 vs. 1998 Interest expense increased $44.3 million in 1999. An increase in the average debt balance outstanding from $324.7 million in 1998 to $988.1 million in 1999 caused interest expense to increase by $43.5 million. The average interest rate on outstanding debt decreased slightly from 6.7% in 1998 to 6.6% in 1999. This rate decrease caused interest expense to decrease $0.5 million in 1999. Other items included in interest expense that are not related to the debt balance outstanding, such as facility and agency fees, amortization of costs and other miscellaneous items, were $1.3 million higher in 1999 compared to 1998. The increase in the average debt balance in 1999 was attributable to the long-term debt assumed in the PennzEnergy merger on August 17, 1999. At that date, Devon assumed $1.6 billion of long-term debt with a weighted average interest rate of 7.2%. In the fourth quarter 1999, Devon retired $350 million of the assumed debt with a portion of the $402 million of net proceeds received from the issuance of 10.3 million shares of Devon common stock. 1998 vs. 1997 Interest expense increased $3.8 million, or 20%, in 1998. The average interest rate increased from 5.4% in 1997 to 6.7% in 1998. The increase in the average rate was primarily due to the fact that Northstar replaced a large portion of its floating-rate debt with longer term, fixed-rate debt early in 1998. The increase in 1998's average rate caused a $4.4 million increase in interest expense. The average debt balance increased from $267.0 million in 1997 to $324.7 million in 1998. This increase in the debt outstanding caused interest expense to increase $3.1 million. The increases caused by higher rates and higher balances outstanding were partially offset by the fact that 1997's interest expense included a $3.3 million "make-whole" payment related to the early retirement of debt. Other items included in interest expense that are not related to the balance of debt outstanding, such as facility and agency fees, amortization of costs and other miscellaneous items, were $0.4 million lower in 1998 compared to 1997. DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT Prior to January 2000, Northstar had certain fixed rate senior notes which were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the 34 35 Canadian dollar from the dates the notes were issued to the dates of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. In mid-January 2000, the U.S. dollar denominated notes were retired prior to maturity with cash on hand and borrowings under Devon's long-term credit facilities. 1999 vs. 1998 The rate of converting Canadian dollars to U.S. dollars increased from $0.6535 at the end of 1998 to $0.6929 at the end of 1999. The balance of Northstar's U.S. dollar denominated notes remained constant at $225 million throughout 1999. The higher conversion rate on the $225 million of debt reduced the Canadian dollar equivalent of debt recorded by Northstar at the end of 1999. Therefore, a $13.2 million reduction to expenses was recorded in 1999. 1998 vs. 1997 The principal balance of Northstar's U.S. dollar denominated notes increased from $135 million at the end of 1997 to $225 million at the end of 1998. The rate of converting Canadian dollars to U.S. dollars decreased from $0.6997 at the end of 1997 to $0.6535 at the end of 1998. The combination of these factors caused $16.1 million to be recorded as an expense in 1998. DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed in Note 9 to the consolidated financial statements included elsewhere herein, Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% Trust Convertible Preferred Securities ("TCP Securities") in July 1996. The TCP Securities had a maturity date of June 15, 2026. However, in October 1999, Devon issued notice to the holders of the TCP Securities that it was exercising its right to redeem such securities on November 30, 1999. Substantially all of the holders of the TCP Securities elected to exercise their conversion rights instead of receiving the redemption cash value. As a result, all but 950 of the 2.99 million units of TCP Securities were exchanged for shares of Devon common stock. As a result, Devon issued approximately 4.9 million shares of common stock for substantially all of the outstanding units of TCP Securities. The redemption price for the 950 units redeemed was approximately $50,000. 1999 vs. 1998 The TCP Securities distributions in 1999 were $6.9 million compared to $9.7 million in 1998. Substantially all of the TCP Securities were exchanged for shares of Devon common stock on November 30, 1999. Therefore, there was no fourth quarter 1999 distribution on the exchanged TCP Securities. 1998 vs. 1997 Distributions on the TCP Securities were $9.7 million in both 1998 and 1997. 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. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less deferred taxes, is written off as an expense. 35 36 1998 Reduction. As of September 30, 1998, the carrying value of Devon's domestic properties, less deferred income taxes, exceeded the full cost ceiling by $88 million. Accordingly, a $126.9 million pre-tax reduction of the carrying value of such properties was recorded in the third quarter of 1998. This reduction was partially offset by a related $38.9 million deferred income tax benefit, resulting in an after-tax charge of $88 million. 1997 Reduction. As of December 31, 1997, the carrying value of Northstar's oil and gas properties, less deferred income taxes, exceeded the full cost ceiling by $397.9 million. Accordingly, a $625.5 million pre-tax reduction of the carrying value of such properties was recorded in the fourth quarter of 1997. This reduction was partially offset by a related $227.6 million deferred income tax benefit, resulting in an after-tax charge of $397.9 million. INCOME TAXES 1999 vs. 1998 Devon's 1999 financial tax rate was 41% of earnings before income tax expense. This rate was higher than the statutory federal tax rate of 35% due to the effect of goodwill amortization that is not deductible for income tax purposes and the effect of Canadian pre-tax earnings being taxed at higher rates than the U.S. rate. The 1998 financial tax benefit rate was 20%. This rate was materially affected by a portion of the $126.9 million reduction of carrying value of oil and gas properties recorded in 1998 that was not deductible for income tax purposes. 1998 vs. 1997 Devon's effective financial income tax benefit rate in 1998 was 20% compared to a benefit rate in 1997 of 37%. The benefit rate in 1998 was lower than in 1997 due to a combination of a smaller pre-tax loss in 1998 and certain 1998 financial expenses that are not deductible for income tax purposes. Approximately $27.2 million of the $126.9 million reduction of carrying value of oil and gas properties related to costs, which are not deductible for income taxes. Also, approximately $5.6 million of the Northstar Combination expenses and $4.0 million of the deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt are not deductible for income tax purposes. CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in "Item 8. Financial Statements and Supplementary Data." CAPITAL EXPENDITURES Approximately $314.8 million was spent in 1999 for capital expenditures, of which $240.7 million was related to the acquisition, drilling or development of oil and gas properties and $69.3 million was spent on the gas gathering and processing project in Wyoming. These amounts compare to 1998 total expenditures of $375.5 million ($371.3 million of which was related to oil and gas properties) and 1997 total expenditures of $288.0 million ($279.9 million of which was related to oil and gas properties.) OTHER CASH USES Devon's common stock dividends were $12.7 million, $7.3 million and $6.4 million in 1999, 1998 and 1997, respectively. Devon also paid $3.7 million of preferred stock dividends in the last 4 1/2 months of 1999 following the PennzEnergy merger. 36 37 CAPITAL RESOURCES AND LIQUIDITY Net cash provided by operating activities ("operating cash flow") has historically been the primary source of Devon's capital and short-term liquidity. Operating cash flow was $205.6 million, $191.6 million and $253.1 million in 1999, 1998 and 1997, respectively. The trends in operating cash flow during these periods have generally followed those of the various revenue and expense items previously discussed. In addition to operating cash flow, Devon's credit lines and the private placement of long-term debt have been an important source of capital and liquidity. In 1999, debt repayments exceeded borrowings by $223.9 million. During the years 1998 and 1997, long-term debt borrowings exceeded repayments by $55.3 million and $127.2 million, respectively. On October 15, 1999, Devon entered into new unsecured long-term credit facilities aggregating $750 million (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $475 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced Devon's previous facilities that totaled $400 million. Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate that is also available at Devon's option. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly. The $475 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $275 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until October 13, 2000 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt borrowed under the Tranche B facility matures two years following the end of the Tranche B Revolving Period. At the end of 1999, Devon had $200 million borrowed under the Tranche A facility and none borrowed under the Tranche B facility. Devon may borrow funds under the $275 million Canadian Facility until October 13, 2000 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 45 and 90 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semi-annual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. At December 31, 1999, there was $114.3 million borrowed under the Canadian Facility. Another significant source of liquidity in 1999 was the $402 million received from the sale of approximately 10.3 million shares of Devon's common stock in a public offering. The proceeds were primarily used to retire $350 million of long-term debt in the fourth quarter of 1999. The retired debt, which Devon assumed in the PennzEnergy merger, had an average interest rate of 10% per year. 37 38 YEAR 2000 STATUS Devon's company-wide Year 2000 Project ("the Project") was completed on schedule. The Project addressed the "Year 2000" issue caused by computer programs being written utilizing two digits rather than four to define an applicable year. Total costs related to the Project were approximately $1.3 million, of which $1.0 million related to capital items and $0.3 million to expense items. During the rollover from December 31, 1999 to January 1, 2000, Devon followed a Year 2000 rollover plan for reporting, documenting and remediating Year 2000 errors. These plans included such tasks as on-site testing and verification of systems at January 1, 2000. Currently, there have been no business-critical failures reported due to Year 2000 errors. However, there were two failures reported for non-critical systems, both of which were remedied by vendor-supplied corrections by January 4, 2000. Devon will continue to monitor systems for errors due to Year 2000 failures through the processing of leap year related data. Devon does not expect to incur significant operational problems due to the Year 2000 issue. However, if all Year 2000 issues are not properly and timely identified, assessed, remediated and tested, there can be no assurances that the Year 2000 issue will not materially impact Devon's results of operations or adversely affect its relationships with customers, vendors, or others. Additionally, there can be no assurance that the Year 2000 issues of other entities will not have a material impact on Devon's systems or results of operations. 2000 ESTIMATES The forward-looking statements provided in this discussion are based on management's examination of historical operating trends, the December 31, 1999 reserve reports of independent petroleum engineers and other data in Devon's possession or available from third parties. Devon cautions that its future oil, gas and NGLs production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of oil and gas. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below. Also, the financial results of Devon's foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks. SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION ESTIMATES Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and world-wide economic growth, weather and other substantially variable factors. These factors are beyond Devon's control and are difficult to predict. In addition to volatility in general, Devon's oil, gas and NGLs prices may vary considerably due to differences between regional markets, transportation availability and demand for different grades of oil, gas and NGLs. Over 97% of Devon's revenues are attributable to sales of these three commodities. Consequently, Devon's financial results and resources are highly influenced by this price volatility. 38 39 Estimates for Devon's future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil and gas will continue at levels that allow for profitable production of these products. There can be no assurance of such stability. Certain of Devon's individual oil and gas properties, such as the Northeast Blanco Unit in the San Juan Basin, are of a size such that significant declines in production at these properties could have a material impact on the overall financial results. The production, transportation and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for Devon's oil, natural gas and NGLs for 2000 will be substantially similar to those of 1999, unless otherwise noted. Given the general limitations expressed herein, Devon's forward-looking statements for 2000 are set forth below. Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Those amounts related to Canadian operations have been converted to U.S. dollars using the year-end 1999 exchange rate of $0.6929 U.S. dollar to $1.00 Canadian dollar. The actual 2000 exchange rate may vary materially from the year-end 1999 rate used. Such variations could have a material effect on the following Canadian estimates. GEOGRAPHIC REPORTING AREAS FOR 2000 The following estimates of production, average price differentials and capital expenditures are provided separately for each of Devon's geographic divisions established after the PennzEnergy merger. These divisions are as follows: o the Southern Division, which operates oil and gas properties located primarily in the onshore South Texas and Gulf Coast areas and offshore in the Gulf of Mexico; o the Northern Division, which operates all properties located in the United States other than those operated by the Southern Division; o Canada; and o International Division, which encompasses all oil and gas properties that lie outside of the United States and Canada. YEAR 2000 POTENTIAL OPERATING ITEMS OIL PRODUCTION Devon expects its oil production in 2000 to total between 21.1 million barrels and 23.9 million barrels. Northern Division production is expected to be between 9.8 million barrels and 11.1 million barrels, Southern Division production is expected to be between 5.7 million barrels and 6.5 million barrels, Canadian production is expected to be between 4.3 million barrels and 4.9 million barrels, and International production is expected to be between 1.3 million barrels and 1.4 million barrels. 39 40 OIL PRICES Devon expects its 2000 net oil prices per barrel will average from $1.50 to $2.40 above West Texas Intermediate ("WTI") posted prices for its Northern Division production and $0.10 to $0.95 above WTI posted prices for its Southern Division production. Devon expects to receive a price from $1.25 to $2.25 below WTI posted prices for its Canadian production. This expected range includes an estimated $0.30 per barrel decrease resulting from foreign currency hedges. These hedges, in which Devon will sell $30 million in 2000 at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same amount of dollars at the floating exchange rate, offset a portion of the exposure to currency fluctuations on those Canadian oil sales that are based on U.S. dollar prices. The $0.30 per barrel decrease is based on the assumption that the year-end 1999 Canadian-to-U.S. conversion rate of $0.6929 remains constant during 2000. Almost 90% of expected International oil production in 2000 is in Venezuela. Due to the terms of the controlling production sharing contract, the net price Devon records for its Venezuelan oil production is substantially less than WTI posted prices. GAS PRODUCTION Devon expects its 2000 gas production to total between 269 Bcf and 306 Bcf. It is expected that Northern Division production will be between 115 Bcf and 130 Bcf, and Southern Division production will be between 93 Bcf and 106 Bcf. Canadian production is expected to be between 61 Bcf and 70 Bcf. No significant gas production is expected in 2000 from Devon's International properties. GAS PRICES - FIXED Through various fixed price contracts or hedging instruments, Devon has fixed the price it will receive in 2000 on a portion of its natural gas production. The Northern Division has fixed volumes of 9.5 Bcf at $1.97 per Mcf, which is a modest amount of total expected Northern Division production. Devon's Canadian operation has fixed volumes of 25.6 Bcf at $1.44 per Mcf, which is a more significant amount of total expected Canadian production. GAS PRICES - FLOATING For the gas production for which prices have not been fixed, Devon's Northern Division production is expected to average from $0.25 less than Texas Gulf Coast spot averages ("TGC") to $0.05 more than TGC, Southern Division production is expected to average from an amount equal to TGC to $0.30 more than TGC and Canadian production is expected to average from $0.40 to $0.80 less than the New York Mercantile Exchange price. NGLS PRODUCTION Devon expects its 2000 production of NGLs to total between 6.6 million barrels and 7.6 million barrels. Between 4.7 million barrels and 5.4 million barrels are expected to be produced in the Northern Division, between 1.5 million barrels and 1.7 million barrels are expected to be produced in the Southern Division, and between 0.4 million barrels and 0.5 million barrels are expected to be produced in Canada. No significant NGLs production is expected in 2000 from Devon's International properties. OTHER REVENUES Devon's other revenues in 2000 are expected to be between $29 million and $33 million. Approximately $18.5 million of 2000's expected other revenues is from dividends on Devon's investment of 7.1 million shares of Chevron Corporation common stock. PRODUCTION AND OPERATING EXPENSES Devon's production and operating expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from Devon's property base, changes in production taxes, general changes in the prices 40 41 of services and materials that are used in the operation of the properties and the amount of repair and workover activity required. Oil, gas and NGLs prices will have a direct effect on production taxes to be incurred in 2000. Future prices also could have an effect on whether proposed workover projects are economically feasible. These factors, coupled with the uncertainty of future oil, gas and NGLs prices, increase the uncertainty inherent in estimating future production and operating costs. Given these uncertainties, Devon estimates that year 2000 total production and operating costs will be between $288 million and $318 million. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2000 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that could be added from drilling or acquisition efforts in 2000 compared to the costs incurred for such efforts, and the revisions to Devon's year-end 1999 reserve estimates that, based on prior experience, are likely to be made during 2000. Devon's consolidated oil and gas property DD&A rate as of January 1, 2000, was $5.41 per Boe. Assuming a full year 2000 oil and gas property DD&A rate of between $5.25 per Boe and $6.00 per Boe, Devon expects that its consolidated oil and gas property DD&A expense in 2000 will be between $400 million and $460 million. In addition to its oil and gas property DD&A expense, Devon also expects to record goodwill amortization in 2000 of between $37 million and $41 million. The goodwill was recorded in connection with the PennzEnergy merger. Additionally, Devon expects its 2000 DD&A expense related to non-oil and gas property fixed assets to total between $27 million and $29 million. GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the costs of many different goods and services used in support of its business. These goods and services are subject to general price level increases or decreases. In addition, Devon's G&A varies with its level of activity and the related staffing needs as well as with the amount of professional services required during any given period. Should Devon's needs or the prices of the required goods and services differ significantly from current expectations, actual G&A could vary materially from the estimate. Given these limitations, consolidated G&A in 2000 is expected to be between $48 million and $53 million. INTEREST EXPENSE Future interest rates and oil, natural gas and NGLs prices have a significant effect on Devon's interest expense. Approximately $1.2 billion of Devon's January 21, 2000, long-term debt balance of $1.7 billion bears interest at fixed rates. Such fixed rates remove the uncertainty of future interest rates from some, but not all, of Devon's long-term debt. Also, Devon can only marginally influence the prices, and the resulting cash flow, it will receive in 2000 from sales of oil, gas and NGLs. These factors increase the margin of error inherent in estimating future interest expense. Other factors, which affect interest expense, such as the amount and timing of capital expenditures, are within Devon's control. Given the uncertainty of future interest rates and commodity prices, Devon estimates that the consolidated interest expense in 2000 will be between $103 million and $114 million. 41 42 DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT Devon's Canadian subsidiary Northstar had $225 million of U.S. dollar denominated debt that gave rise to this item in prior periods. This debt was retired in January 2000. The Canadian-to-U.S. dollar exchange rate dropped slightly in January prior to the debt retirement. As a result, $2.4 million of expense was recognized in January 2000. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES As of December 31, 1999, the full cost ceiling exceeded Devon's carrying value of oil and gas properties, less deferred income taxes. However, such excess could easily be eliminated by declines in oil and/or gas prices between year-end 1999 and the end of any quarter during 2000. The result would be a 2000 reduction of the carrying value of oil and gas properties. INCOME TAXES Devon expects its consolidated financial income tax rate in 2000 to be between 48% and 57%. These rates are the combined current and deferred tax rates. There are certain items that will have a fixed impact on 2000's income tax expense regardless of the level of pre-tax earnings that are produced. These items include Section 29 tax credits in the U.S., which reduce income taxes based on production levels of certain properties and are not necessarily affected by pre-tax financial earnings. The amount of Section 29 tax credits expected to be used to offset financial income tax expense in 2000 is approximately $4 million. Also, Devon's Canadian subsidiaries are subject to Canada's "large corporation tax" of approximately $2 million, which is based on total capitalization levels, not pre-tax earnings. The financial income tax in 2000 will also be increased by approximately $16 million due to the financial amortization of certain costs, such as goodwill amortization, that are not deductible for income tax purposes. Significant changes in estimated production levels of oil, gas and NGLs, the prices of such products, or any of the various expense items could materially alter the effect of the aforementioned items on 2000's financial income tax rates. Based on its current expectations of 2000 taxable income, Devon anticipates its current portion of 2000 income taxes will be $36 million to $40 million. However, unanticipated revenue and/or expense fluctuations could easily make these tax estimates inaccurate. PROPERTY ACQUISITIONS AND DIVESTITURES Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget," nor can it reasonably predict, the timing or size of such possible acquisitions, if any. During 2000, Devon contemplates the disposition of certain oil and gas properties (the "Disposition Properties"). The Disposition Properties are predominantly properties that are either outside of Devon's core-operating areas or otherwise do not fit Devon's current strategic objectives. Most, but not all, of such properties were acquired in the August 1999 merger with PennzEnergy. The Disposition Properties are located in the U.S., Canada and other International areas. At this time, Devon is in the early stages of the disposition process, and it is impossible to identify when, or if, the dispositions will occur. The estimates of Devon's 2000 results set forth earlier in this section include the full-year results from the Disposition Properties without any effect given to their potential disposition. The actual effect the dispositions will have on Devon's overall estimates will depend upon the actual timing of the dispositions. The estimated full-year results from the Disposition Properties that are included in the overall 2000 estimates include oil production of between 4.1 million barrels and 4.6 42 43 million barrels, gas production of between 2.1 Bcf and 2.3 Bcf and NGLs production of between 0.9 million barrels and 1.0 million barrels and production and operating expenses of between $37.8 million and $41.8 million. Because Devon is in the early stages of the disposition process, it is difficult to accurately predict the amount of proceeds to be generated from the property dispositions. However, the dispositions are expected to increase Devon's oil and gas property depreciation, depletion and amortization rate by $0.35 per Boe to $0.45 per Boe after all dispositions are completed. YEAR 2000 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY CAPITAL EXPENDITURES Devon's capital expenditures budget is based on an expected range of future oil, natural gas and NGLs prices as well as the expected costs of the capital additions. Should Devon's price expectations for its future production change significantly, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2000 capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon's estimates. Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget", nor can it reasonably predict, the timing or size of such possible acquisitions, if any. Devon expects its capital expenditures for the year 2000 will be materially higher than those for 1999. For 1999, Devon's capital expenditures for exploration, drilling and development efforts were $217 million. However, for the year 2000, Devon expects capital expenditures for exploration, drilling and development efforts to total between $480 million and $510 million. These amounts include between $110 million and $130 million for drilling and facilities costs related to reserves classified as proved as of year-end 1999. In addition, these amounts include between $240 million and $260 million for other lower risk/reward projects and between $120 million and $130 million for new, higher risk/reward projects. The following table shows expected drilling and facilities expenditures by major operating division. EXPLORATION, DRILLING AND PRODUCTION FACILITIES EXPENDITURES ($ IN MILLIONS) ----------------------------------------------------------------------------
NORTHERN SOUTHERN INTERNATIONAL DIVISION DIVISION CANADA DIVISION --------- ---------- --------- ------------- Related to Proved Reserves $60 -$ 70 $30 -$ 35 $5 -$ 10 $8 -$12 Lower Risk/Reward Projects $100-$110 $65 -$ 75 $70 -$ 80 -- Higher Risk/Reward Projects $15 -$ 20 $45 -$ 50 $30 -$ 35 $22-$28 Total $175-$200 $140-$160 $105-$125 $30-$40
In addition to these expenditures for exploration, drilling and development, Devon is participating through a joint venture in the construction of gas gathering and processing systems in the Powder River Basin of Wyoming. Devon expects to spend from $10 million to $20 million as its share of the project in 2000. Devon also expects to capitalize between $25 million and $35 million of G&A expenses in accordance with the full cost method of accounting. Also, Devon expects to spend from $10 million to $20 million for plugging and abandonment costs on some of its oil and gas properties. 43 44 OTHER CASH USES Devon's management expects the policy of paying a quarterly dividend to continue. With the current $0.05 per share quarterly dividend rate and 86.1 million shares of common stock outstanding, 2000 dividends on common stock are expected to approximate $17 million. Dividends paid on preferred stock should total $9.7 million in 2000. CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2000 cash uses, including its exploration, drilling and development activities, are expected to be funded primarily through a combination of working capital and operating cash flow, with the remainder, if any, funded with borrowings from Devon's credit facilities. The amount of operating cash flow to be generated during 2000 is uncertain due to the factors affecting revenues and expenses as previously cited. However, Devon expects its combined capital resources to be more than adequate to fund its anticipated capital expenditures and other cash uses for 2000. As of January 21, 2000, Devon had $337 million available under its $750 million credit facilities. If significant acquisitions or other unplanned capital requirements arise during the year, Devon could utilize its existing credit facilities and/or seek to establish and utilize other sources of financing. IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of all derivatives as either assets or liabilities in the statement of financial position and measurement of those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge. The accounting for changes in the fair value of a derivative (that is gains and losses) depends on the intended use of the derivative and whether it qualifies as a hedge. A subsequent pronouncement, SFAS 137, was issued in July, 1999 that delayed the effective date of SFAS 133 until fiscal years beginning after June 15, 2000. Devon plans to adopt the provision of SFAS 133 in the first quarter of the year ending December 31, 2001, and is currently evaluating the effects of this pronouncement. 44 45 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 and gas 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 Devon's market risk sensitive instruments were entered into for purposes other than trading. COMMODITY PRICE RISK Devon's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to its U.S. and Canadian natural gas production. Pricing for oil and gas 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 financial price swaps whereby Devon will receive a fixed price for its production and pay a variable market price to the contract counterparty. 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. Realized gains or losses from the settlement of these financial hedging instruments are recognized in oil and gas sales when the associated production occurs. The gains and losses realized as a result of these hedging activities are substantially offset in the cash market when the hedged commodity is delivered. Devon does not hold or issue derivative instruments for trading purposes. As of year-end 1999, Devon had financial gas price hedging instruments in place which represented approximately 18 Bcf, 13 Bcf and 3 Bcf of gas production in the years 2000, 2001 and 2002, respectively. The 2000 hedged gas volumes represent approximately 6% of expected 2000 total production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2000 Estimates." 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, 1999, a 10% increase in the underlying commodities' prices would have reduced the fair value of Devon's commodity hedging instruments by $7.7 million. In addition to the commodity hedging instruments described above, Devon also manages its exposure to gas price risks by periodically entering into fixed-price gas contracts. All of Devon's existing fixed-price contracts relate to its Canadian gas production. For each of the years of 2000 through 2004, Devon's fixed-price gas contracts cover approximately 17 Bcf, 12 Bcf, 10 Bcf, 6 Bcf and 6 Bcf of production, respectively. Devon also has Canadian gas volumes subject to fixed-price contracts in the years from 2005 through 2016, but the yearly volumes are less than 6 Bcf. The amount of 2000's production covered by fixed-price contracts represents approximately 6% of expected 2000 total production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2000 Estimates." 45 46 INTEREST RATE RISK At December 31, 1999, Devon had long-term debt outstanding of $1.79 billion. Of this amount, $1.47 billion, or 82%, bears interest at fixed rates averaging 6.9%. The remaining $0.32 billion of debt outstanding at the end of 1999 bears interest at floating rates which averaged 6.2% at the end of 1999. In mid-January 2000, Devon utilized $75 million of cash on hand and $150 million of borrowings from its long-term credit facilities, which bear interest at floating rates, to retire $225 million of fixed-rate long-term debt. This fixed-rate debt retired had an average interest rate of 6.8% per year. Also in mid-January 2000, Devon used approximately $50 million of cash on hand to reduce year-end 1999 borrowings under its credit facilities. These early 2000 transactions left Devon with $1.66 billion of total long-term debt, of which $1.25 billion, or 75%, bears interest at fixed rates averaging 6.9%. The remaining $0.41 billion of floating-rate debt borrowed under the credit facilities bears interest, as of January 21, 2000, at an average rate of 6.0%. The terms of the credit facilities in place allow interest rates to be fixed at Devon's option for periods of between 30 to 180 days. A 10% increase in short-term interest rates on the floating-rate debt outstanding as of January 21, 2000, would equal approximately 60 basis points. Such an increase in interest rates would increase Devon's 2000 interest expense by approximately $2.5 million assuming borrowed amounts remain outstanding. 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 foreign subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. Assets and liabilities of the foreign 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. Substantially all of Devon's Canadian oil sales are paid in Canadian dollars, but at amounts based on the U.S. dollar price of oil. Therefore, currency fluctuations between the Canadian and U.S. dollars impact the amount of Canadian dollars received by Devon's Canadian subsidiaries for their oil production. To mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues, Devon has existing foreign currency exchange rate swaps. Under such swap agreements, in 2000 Devon will sell $30 million at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same amount of dollars at the floating exchange rate. The amount of gains or losses realized from such swaps are included as increases or decreases to realized oil sales. At the year-end 1999 exchange rate, these swaps would result in decreases to 2000's annual oil sales of approximately $1.4 million. A further $0.03 decrease in the Canadian-to-U.S. dollar exchange rate in 2000 would result in an additional decrease in oil sales of approximately $1.3 million. For purposes of the sensitivity analysis described above for changes in the Canadian dollar exchange rate, a change in the rate of $0.03 was used as opposed to a 10% change in the rate. During the last seven years, the Canadian-to-U.S. dollar exchange rate has fluctuated an average of approximately 4% per year, and no year's fluctuation was greater than 7%. The $0.03 change used in the above analysis represents an approximate 4% change in the year-end 1999 rate. 46 47 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
Page ---- Independent Auditors' Reports.............................................. 48 Consolidated Financial Statements: Consolidated Balance Sheets December 31, 1999, 1998 and 1997....................................... 50 Consolidated Statements of Operations Years Ended December 31, 1999, 1998 and 1997........................... 51 Consolidated Statements of Stockholders' Equity Years Ended December 31, 1999, 1998 and 1997........................... 52 Consolidated Statements of Cash Flows Years Ended December 31, 1999, 1998 and 1997........................... 53 Notes to Consolidated Financial Statements December 31, 1999, 1998 and 1997....................................... 54
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. 47 48 INDEPENDENT AUDITORS' REPORT 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, 1999, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. 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 did not audit the 1998 and 1997 financial statements of Northstar Energy Corporation, a wholly-owned subsidiary, which statements reflect total assets constituting 31% and 32% and total revenues constituting 38% and 37% in 1998 and 1997, respectively, of the related consolidated totals. The 1998 and 1997 financial statements of Northstar Energy Corporation were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Northstar Energy Corporation in 1998 and 1997, is based solely on the reports of the other auditors. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion. In our opinion, based on our audits and the reports of the other auditors, 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, 1999, 1998 and 1997, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles. KPMG LLP Oklahoma City, Oklahoma February 9, 2000 48 49 AUDITORS' REPORT TO THE SHAREHOLDERS We have audited the consolidated balance sheets of Northstar Energy Corporation (a wholly owned subsidiary of Devon Energy Corporation) as at December 31, 1998 and 1997 and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity and cash flows for the years then ended (not separately included herein). These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards, which are substantially similar to generally accepted auditing standards in the United States. Those standards require that we plan and perform an audit to obtain reasonable assurance 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. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 1998 and 1997, and the results of its operations and the changes in its cash flow for the years then ended in accordance with generally accepted accounting principles in the United States. /s/ DELOITTE & TOUCHE LLP ------------------------------------- Deloitte & Touche LLP Chartered Accountants Calgary, Alberta Canada January 20, 1999 49 50 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, --------------------------------------------- 1999 1998 1997 ----------- ----------- ----------- ASSETS Current assets: Cash and cash equivalents $ 167,167 19,154 42,065 Accounts receivable 209,405 83,858 96,828 Inventories 13,441 2,750 4,012 Assets held for sale -- -- 43,548 Deferred income taxes 4,886 605 434 Investments and other current assets 22,295 4,281 26,370 ----------- ----------- ----------- Total current assets 417,194 110,648 213,257 ----------- ----------- ----------- Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties 4,974,810 2,610,511 2,320,735 Less accumulated depreciation, depletion and amortization 1,818,890 1,509,583 1,325,452 ----------- ----------- ----------- 3,155,920 1,100,928 995,283 Investment in Chevron Corporation common stock, at fair value 614,382 -- -- Goodwill, net of amortization 322,800 -- -- Other assets 112,864 14,780 40,446 ----------- ----------- ----------- Total assets $ 4,623,160 1,226,356 1,248,986 =========== =========== =========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade 75,625 40,177 46,003 Revenues and royalties due to others 58,130 12,508 13,898 Income taxes payable 11,287 -- 5,029 Current portion of long-term debt -- -- 48,979 Accrued interest payable 26,270 3,688 6,274 Merger related expenses payable 32,504 7,882 -- Accrued expenses 23,628 16,401 16,131 ----------- ----------- ----------- Total current liabilities 227,444 80,656 136,314 ----------- ----------- ----------- Other liabilities 192,210 34,747 29,464 Debentures exchangeable into shares of Chevron Corporation common stock 760,313 -- -- Other long-term debt 1,026,808 405,271 305,337 Deferred income taxes 390,865 33,219 31,825 Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trust holding solely 6.5% convertible junior subordinated debentures of Devon Energy Corporation -- 149,500 149,500 Stockholders' equity: Preferred stock of $1.00 par value ($100 liquidation value) Authorized 4,500,000 shares; issued 1,500,000 in 1999 and none in 1998 and 1997 1,500 -- -- Common stock of $.10 par value Authorized 400,000,000 shares; issued 86,085,000 in 1999, 48,425,000 in 1998, and 48,290,000 in 1997 8,608 4,842 4,829 Additional paid-in capital 2,246,652 796,992 794,176 Retained earnings (accumulated deficit) (164,698) (242,909) (175,346) Accumulated other comprehensive loss (66,542) (35,962) (27,113) ----------- ----------- ----------- Total stockholders' equity 2,025,520 522,963 596,546 ----------- ----------- ----------- Commitments and contingencies (Notes 12 and 13) Total liabilities and stockholders' equity $ 4,623,160 1,226,356 1,248,986 =========== =========== ===========
See accompanying notes to consolidated financial statements 50 51 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ------------------------------------------ 1999 1998 1997 ---------- ---------- ---------- REVENUES Oil sales $ 273,234 143,624 207,725 Gas sales 385,925 209,344 219,459 Natural gas liquids sales 56,344 16,692 24,920 Other 18,996 17,848 47,555 ---------- ---------- ---------- Total revenues 734,499 387,508 499,659 ---------- ---------- ---------- COSTS AND EXPENSES Lease operating expenses 166,848 113,484 100,897 Production taxes 23,055 13,916 19,227 Depreciation, depletion and amortization of property and equipment 254,275 123,844 169,108 Amortization of goodwill 16,111 -- -- General and administrative expenses 53,845 23,554 24,381 Northstar Combination expenses -- 13,149 -- Interest expense 66,913 22,632 18,788 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860 Distributions on preferred securities of subsidiary trust 6,884 9,717 9,717 Reduction of carrying value of oil and gas properties -- 126,900 625,514 ---------- ---------- ---------- Total costs and expenses 574,777 463,300 973,492 ---------- ---------- ---------- Earnings (loss) before income tax expense (benefit) 159,722 (75,792) (473,833) INCOME TAX EXPENSE (BENEFIT) Current 24,656 7,687 26,857 Deferred 40,510 (23,194) (200,699) ---------- ---------- ---------- Total income tax expense (benefit) 65,166 (15,507) (173,842) ---------- ---------- ---------- Net earnings (loss) 94,556 (60,285) (299,991) Preferred stock dividends 3,651 -- -- ---------- ---------- ---------- Net earnings (loss) applicable to common shareholders $ 90,905 (60,285) (299,991) ========== ========== ========== Net earnings (loss) per average common share outstanding: Basic $ 1.51 (1.25) (6.38) ========== ========== ========== Diluted $ 1.46 (1.25) (6.38) ========== ========== ========== Weighted average common shares outstanding - basic 60,015 48,376 47,040 ========== ========== ==========
See accompanying notes to consolidated financial statements. 51 52 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
ACCUMU- RETAINED LATED EARNINGS OTHER TOTAL ADDITIONAL (ACCUMU- COMPRE- STOCK- PREFERRED COMMON PAID-IN LATED HENSIVE HOLDERS' STOCK STOCK CAPITAL DEFICIT) LOSS EQUITY ---------- ----- --------- -------- ------- --------- Balance as of December 31, 1996 $ -- 4,288 556,049 131,090 (12,655) 678,772 Comprehensive loss: Net loss -- -- -- (299,991) -- (299,991) Other comprehensive loss - foreign currency translation adjustments -- -- -- -- (14,458) (14,458) ---------- Comprehensive loss -- -- -- -- -- (314,449) Stock issued -- 1,027 453,441 -- -- 454,468 Stock repurchased -- (486) (216,514) -- -- (217,000) Tax benefit related to employee stock options -- -- 1,200 -- -- 1,200 Dividends on common stock -- -- -- (6,445) -- (6,445) ---------- -------- ---------- ---------- --------- ---------- Balance as of December 31, 1997 -- 4,829 794,176 (175,346) (27,113) 596,546 Comprehensive loss: Net loss -- -- -- (60,285) -- (60,285) Other comprehensive loss, net of tax: Foreign currency translation adjustments -- -- -- -- (8,130) (8,130) Minimum pension liability adjustment -- -- -- -- (719) (719) ---------- Other comprehensive loss -- -- -- -- -- (8,849) ---------- Comprehensive loss -- -- -- -- -- (69,134) Stock issued -- 13 2,816 -- -- 2,829 Dividends on common stock -- -- -- (7,278) -- (7,278) ---------- ----- --------- -------- ------- --------- Balance as of December 31, 1998 -- 4,842 796,992 (242,909) (35,962) 522,963 Comprehensive earnings: Net earnings -- -- -- 94,556 -- 94,556 Other comprehensive loss, net of tax: Foreign currency translation adjustments -- -- -- -- 7,517 7,517 Minimum pension liability adjustment -- -- -- -- (241) (241) Unrealized losses on marketable securities -- -- -- -- (37,856) (37,856) ---------- Other comprehensive loss -- -- -- -- -- (30,580) ---------- Comprehensive earnings -- -- -- -- -- 63,976 Stock issued 1,500 3,766 1,448,706 -- -- 1,453,972 Tax benefit related to employee stock options -- -- 954 -- -- 954 Dividends on common stock -- -- -- (12,694) -- (12,694) Dividends on preferred stock -- -- -- (3,651) -- (3,651) ---------- ----- --------- -------- ------- --------- Balance as of December 31, 1999 $ 1,500 8,608 2,246,652 (164,698) (66,542) 2,025,520 ========== ======== ========== ========== ========= ==========
See accompanying notes to consolidated financial statements. 52 53 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, --------------------------------------------- 1999 1998 1997 ----------- ------ ------ CASH FLOWS FROM OPERATING ACTIVITIES Net earnings (loss) $ 94,556 (60,285) (299,991) Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: Depreciation, depletion and amortization of property and equipment 254,275 123,844 169,108 Amortization of goodwill 16,111 -- -- Amortization of premiums on debentures (1,328) -- -- Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860 Reduction of carrying value of oil and gas properties -- 126,900 625,514 Gain on sale of assets (122) (164) (29,573) Deferred income taxes (benefit) 40,510 (23,194) (200,699) Other -- 901 2,964 Changes in assets and liabilities, net of effects of acquisitions of businesses: (Increase) decrease in: Accounts receivable (54,416) 10,160 (17,404) Inventories (3,014) 1,173 198 Prepaid expenses (1,518) 449 (930) Other assets (22,073) 130 (874) (Decrease) increase in: Accounts payable (39,195) (3,439) 300 Income taxes payable (19,418) (5,126) 269 Accrued expenses (30,187) 7,000 132 Long-term other liabilities (15,399) (2,882) (1,818) ----------- ----------- ----------- Net cash provided by operating activities 205,628 191,571 253,056 ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of property and equipment 77,584 62,997 180,296 Proceeds from sale of investments -- 42,584 -- Capital expenditures (314,805) (375,512) (287,991) Payments made for acquisition of business, net of cash acquired (17,215) -- -- Increase in equity investment -- -- (32,428) Decrease (increase) in other assets 719 (2,029) (7,460) ----------- ----------- ----------- Net cash used in investing activities (253,717) (271,960) (147,583) ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings on long-term debt 1,705,917 1,292,020 817,785 Principal payments on long-term debt (1,929,809) (1,236,713) (690,627) Issuance of common stock, net of issuance costs 422,232 2,829 12,878 Retirement of preferred securities of subsidiary trust (50) -- -- Repurchase of common stock -- -- (217,000) Dividends paid on common stock (12,694) (7,278) (6,445) Dividends paid on preferred stock (3,651) -- -- Increase in long-term other liabilities 13,453 6,760 6,268 ----------- ----------- ----------- Net cash provided by (used in) financing activities 195,398 57,618 (77,141) ----------- ----------- ----------- Effect of exchange rate changes on cash 704 (140) 316 ----------- ----------- ----------- Net increase (decrease) in cash and cash equivalents 148,013 (22,911) 28,648 Cash and cash equivalents at beginning of year 19,154 42,065 13,417 ----------- ----------- ----------- Cash and cash equivalents at end of year $ 167,167 19,154 42,065 =========== =========== ===========
See accompanying notes to consolidated financial statements. 53 54 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Accounting policies used by Devon Energy Corporation and subsidiaries ("Devon") reflect industry practices and conform to generally accepted accounting principles. The more significant of such policies are briefly discussed below. Basis of Presentation and Principles of Consolidation Devon is engaged primarily in oil and gas exploration, development and production, and the acquisition of producing properties. Such activities domestically are located primarily in five operating areas: Permian Basin, Mid-Continent, the Rocky Mountains, Gulf Coast onshore and offshore 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 and Venezuela. Devon's share of the assets, liabilities, revenues and expenses of affiliated partnerships and the accounts of its wholly-owned subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation. Information concerning common stock and per share data assumes the exchange of all Exchangeable Shares issued in connection with the Northstar Combination described in Note 2. Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with generally accepted accounting principles 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. Actual amounts could differ from those estimates. Inventories Inventories, which consist primarily of injected gas and tubular goods, parts and supplies, are stated at cost, determined principally by the average cost method, which is not in excess of net realizable value. 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. Net capitalized costs are limited to the estimated future net revenues, discounted at 10% per annum, from proved oil, natural gas and natural gas liquids reserves. Such limitations are imposed separately on a country-by-country basis. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of one barrel of oil to six 54 55 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 thousand cubic feet of natural gas. 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. Depreciation and amortization of other property and equipment, including leasehold improvements, are provided using the straight-line method based on estimated useful lives from 3 to 39 years. Marketable Securities and Other Investments Devon accounts for certain investments in debt and equity securities by following the requirements of Statement of Financial Accounting Standards ("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity Securities." This standard requires that, except for debt securities classified as "held-to-maturity," investments in debt and equity securities must be reported at fair value. As a result, Devon's investment in Chevron Corporation common stock, which is classified as "available for sale," is reported at fair value, with the tax effected unrealized gain or loss recognized in other comprehensive earnings and reported as a separate component of stockholders' equity. Devon's investments in other short-term securities are also classified as "available for sale." Goodwill Goodwill, which represents the excess of purchase price over the fair value of net assets acquired, is amortized by an equivalent unit-of-production method. Devon assesses the recoverability of this intangible asset by determining whether the amortization of the goodwill balance over its remaining life can be recovered through undiscounted future operating cash flows of the acquired properties. The amount of goodwill impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate reflecting Devon's average cost of funds. The assessment of the recoverability of goodwill will be impacted if estimated future operating cash flows are not achieved. Accumulated amortization of goodwill was $16.1 million at December 31, 1999. Revenue Recognition and Gas Balancing Oil and gas revenues are recognized when produced. During the course of normal operations, Devon and other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes produced. These volumetric imbalances are monitored over the lives of the wells' production capability. If an imbalance exists at the time the wells' reserves are depleted, cash settlements are made among the joint interest owners under a variety of arrangements. Devon follows the sales method of accounting for gas imbalances. A liability is recorded when Devon's excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No 55 56 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 receivables are recorded for those wells where Devon has taken less than its ownership share of gas production. Hedging Activities Devon has periodically entered into oil and gas price swaps and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are predominantly based on U.S. dollar prices. The hedging instruments are usually placed with counterparties that Devon believes are minimal credit risks. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon. Devon accounts for its hedging instruments using the deferral method of accounting. Under this method, realized gains and losses from Devon's price risk management activities are recognized in oil and gas revenues when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses on hedging contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a hedging instrument and actual oil and gas prices, a gain or loss is recognized currently to the extent the hedging instrument has not offset changes in actual oil and gas prices. 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 would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, "Accounting for Stock-Based Compensation," established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123 which are included in Note 10. Major Purchasers In 1999, Columbia Energy Services Corporation accounted for 12% of Devon's combined oil, gas and natural gas liquids sales. Also, Aquila Energy Marketing Corporation accounted for 19% and 15% of Devon's combined oil, gas and natural gas liquids sales in 1998 and 1997, respectively. 56 57 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 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. U.S. deferred income taxes have not been provided on Canadian earnings which are being permanently reinvested. General and Administrative Expenses General and administrative expenses are reported net of amounts allocated to 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) or if Devon's Trust Convertible Preferred Securities were converted to common stock. Substantially all of Devon's Trust Convertible Preferred Securities were converted to common stock on November 30, 1999 (see Note 9). The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted net earnings per share for the year 1999. The diluted loss per share calculations for 1998 and 1997 produce results that are anti-dilutive. (The diluted calculation for 1998 reduced the net loss by $6.0 million and increased the common shares outstanding by 5.5 million shares. The 1997 diluted calculation reduced the net loss by $6.0 million and increased the common shares outstanding by 5.6 million shares.) Therefore, the diluted loss per share amounts for 1998 and 1997 reported in the accompanying consolidated statements of operations are the same as the basic loss per share amounts. 57 58 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
NET WEIGHTED EARNINGS AVERAGE NET APPLICABLE COMMON EARNINGS TO COMMON SHARES PER STOCKHOLDERS OUTSTANDING SHARE ------------ ----------- -------- (IN THOUSANDS) Year ended December 31, 1999: Basic earnings per share $90,905 60,015 $ 1.51 ======= Dilutive effect of: Potential common shares issuable upon the conversion of Trust Convertible Preferred securities (the increase in net earnings is net of income tax expense of $2,742,000) 4,289 4,485 Potential common shares issuable upon the exercise of employee stock options -- 713 ------- ------- Diluted earnings per share $95,194 65,213 $ 1.46 ======= ======= =======
Options to purchase approximately 2.5 million shares of Devon's common stock, with exercise prices ranging from $36.28 per share to $92.78 per share (with a weighted average price of $52.74 per share), were excluded from the diluted earnings per share calculation for 1999. The excluded options for 1999 expire between April 26, 2000 and September 30, 2009. All options were excluded from the diluted earnings per share calculations for 1998 and 1997. Comprehensive Earnings (Loss) Devon adopted SFAS No. 130, "Reporting Comprehensive Income," on January 1, 1998. SFAS No. 130 was effective for fiscal years beginning after December 15, 1997. SFAS No. 130 established standards for reporting and display of comprehensive income and its components. Devon's comprehensive income information is included in the accompanying consolidated statements of stockholders' equity. A summary of accumulated other comprehensive loss as of December 31, 1999, 1998 and 1997, and changes during each of the years then ended, is presented in the following table. 58 59 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
FOREIGN MINIMUM CURRENCY PENSION UNREALIZED TRANSLATION LIABILITY LOSSES ON ADJUST- ADJUST- MARKETABLE MENTS MENTS SECURITIES TOTAL ---------- ---------- ---------- ---------- (IN THOUSANDS) Balance as of December 31, 1996 $ (12,655) -- -- (12,655) 1997 activity (14,458) -- -- (14,458) ---------- ---------- ---------- ---------- Balance as of December 31, 1997 (27,113) -- -- (27,113) 1998 activity (8,130) (1,179) -- (9,309) Deferred taxes -- 460 -- 460 ---------- ---------- ---------- ---------- 1998 activity, net of deferred taxes (8,130) (719) -- (8,849) ---------- ---------- ---------- ---------- Balance as of December 31, 1998 (35,243) (719) -- (35,962) 1999 activity 7,517 (394) (62,059) (54,936) Deferred taxes -- 153 24,203 24,356 ---------- ---------- ---------- ---------- 1999 activity, net of deferred taxes 7,517 (241) (37,856) (30,580) ---------- ---------- ---------- ---------- Balance as of December 31, 1999 $ (27,726) (960) (37,856) (66,542) ========== ========== ========== ==========
Foreign Currency Translation Adjustments The assets and liabilities of certain foreign subsidiaries are prepared in their respective local currencies and 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 loss. Dividends Dividends on Devon's common stock were paid in 1999, 1998 and 1997 at a per share rate of $0.05 per quarter. As adjusted for the Northstar Combination's pooling-of-interests method of accounting, annual dividends per share for 1998 and 1997 were $0.15 and $0.14, respectively. Statements of Cash Flows For purposes of the consolidated statements of cash flows, Devon considers all highly liquid investments with original maturities of three months or less to be cash equivalents. 59 60 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 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 generally accepted accounting principles. 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 13 for a discussion of amounts recorded for these liabilities. Reclassifications Certain of the 1998 and 1997 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 1999 presentation. 2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION PennzEnergy Merger Devon closed its merger with PennzEnergy Company ("PennzEnergy") on August 17, 1999. The merger was accounted for using the purchase method of accounting for business combinations. Accordingly, the accompanying statement of operations for 1999 includes the effects of PennzEnergy operations since August 17, 1999. Devon issued approximately 21.5 million shares of its common stock to the former stockholders of PennzEnergy. In addition, Devon assumed long-term debt and other obligations totaling approximately $2.3 billion on August 17, 1999. The calculation of the total purchase price and the preliminary allocation to assets and liabilities as of August 17, 1999, are shown below. Devon intends to sell certain of the assets acquired. Generally, the proceeds from such sales will reduce the gross purchase price allocated to oil and gas properties. 60 61 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
(IN THOUSANDS, EXCEPT SHARE PRICE) Calculation and preliminary allocation of purchase price: Shares of Devon common stock issued to PennzEnergy stockholders 21,501 Average Devon stock price $33.40 ----------- Fair value of common stock issued $ 718,177 Plus preferred stock assumed by Devon 150,000 Plus estimated merger costs incurred 71,545 Plus fair value of PennzEnergy employee stock options assumed by Devon 18,295 Less stock registration and issuance costs incurred (4,985) ----------- Total purchase price 953,032 Plus fair value of liabilities assumed by Devon: Current liabilities 200,708 Debentures exchangeable into Chevron Corporation common stock 760,313 Other long-term debt 838,792 Other long-term liabilities 158,988 ---------- 2,911,833 Less fair value of non oil and gas assets acquired by Devon: Current assets 109,769 Non oil and gas properties 31,412 Investment in common stock of Chevron Corporation 676,441 Other assets 81,945 ----------- Fair value allocated to oil and gas properties, including $83.3 million of undeveloped leasehold $2,012,266 =========
Additionally, $338.9 million was added as goodwill for deferred taxes created as a result of the merger. Due to the tax-free nature of the merger, Devon's tax basis in the assets acquired and liabilities assumed are the same as PennzEnergy's tax basis. The $338.9 million of deferred taxes recorded represent the deferred tax effect of the differences between the fair values assigned by Devon for financial reporting purposes to the former PennzEnergy assets and liabilities and their bases for income tax purposes. Estimated proved reserves added in the PennzEnergy merger were 232.7 million barrels of oil, 782.6 billion cubic feet of natural gas and 32.7 million barrels of natural gas liquids. Also, added in the PennzEnergy merger were approximately 13 million net acres of undeveloped leasehold. (The quantities of proved reserves stated in this paragraph are unaudited.) Wascana Properties Transaction On December 23, 1998, Devon acquired certain natural gas properties located in northeastern Alberta, Canada, from Wascana Oil and Gas Partnership, a subsidiary of Canadian Occidental Petroleums Ltd. (the "Wascana Properties"). Devon acquired the properties for 61 62 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 approximately $57.5 million, which was funded with bank debt under Devon's then existing credit facilities. Estimated proved reserves of the Wascana Properties as of December 31, 1998, were 71.5 billion cubic feet of natural gas. Approximately $52.2 million of the purchase price was allocated to the proved reserves. The remaining $5.3 million of the purchase price was allocated to approximately 190,000 net undeveloped acres and exclusive rights to associated seismic data. (The quantities of proved reserves stated in this paragraph are unaudited.) Pro Forma Information Set forth in the following table is certain unaudited pro forma financial information for the years ended December 31, 1999 and 1998. This information has been prepared assuming the PennzEnergy merger and the Wascana Property transaction were consummated on January 1, 1998, and 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, 1998. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions. The pro forma information includes the effect of Devon's issuance of 10.3 million shares of common stock as if such shares had been issued on January 1, 1998. (See Note 10 for additional information on this issuance of shares of common stock.) The pro forma information assumes that the approximately $402 million of net proceeds from the issuance of common stock was used to retire long-term debt and therefore reduce interest expense. The following should be considered in connection with the pro forma financial information presented: o Expected annual cost savings of $50 to $60 million related to the PennzEnergy merger have not been reflected as an adjustment to the historical data in preparing the following pro forma information. These cost savings are expected to result from the consolidation of the corporate headquarters of Devon and PennzEnergy and the elimination of duplicate staff and expenses. o The 1999 pro forma results include a gain of $46.7 million ($29.8 million after-tax) from PennzEnergy's pre-merger sale of land, timber and mineral rights in Pennsylvania and New York. o In 1998, PennzEnergy realized pretax gains on the sale and exchange of Chevron Corporation common stock of $203.1 million. This gain is included in the 1998 pro forma financial information presented in the following table. The pro forma 62 63 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 financial information does not include the related $207.0 million after-tax extraordinary loss resulting from the early extinguishment of debt. The exclusion of the extraordinary loss from the 1998 pro forma results is required by Securities and Exchange Commission rules and regulations regarding presentation of pro forma results of operations, and is consistent with the pro forma results presented in the PennzEnergy merger proxy statement filed in 1999. If the extraordinary loss were included in the 1998 pro forma results, the 1998 pro forma net loss as presented in the following table would be $301 million, or $3.83 per share. o The 1998 pro forma results include $24.3 million of nonrecurring general and administrative expenses in connection with the spin-off of Pennzoil-Quaker State Company on December 30, 1998. o The 1998 pro forma results include a reduction of the carrying value of oil and gas properties incurred by Devon. This reduction, which was due to the full cost ceiling limitation, was $126.9 million ($88.0 million after-tax). 63 64 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
PRO FORMA INFORMATION YEAR ENDED DECEMBER 31, ------------------------------ 1999 1998 (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES Oil sales $ 389,977 302,918 Gas sales 581,937 571,485 Natural gas liquids sales 82,229 63,726 Other 85,153 295,803 ------------ ------------ Total revenues 1,139,296 1,233,932 ------------ ------------ COSTS AND EXPENSES Lease operating expenses 262,955 297,217 Production taxes 32,006 28,148 Depreciation, depletion and amortization of property and equipment 470,265 488,608 Amortization of goodwill 46,321 52,637 General and administrative expenses 109,328 139,378 Northstar Combination expenses -- 13,149 Interest expense 110,413 138,482 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (13,154) 16,104 Distributions on preferred securities of subsidiary trust 6,884 9,717 Reduction of carrying value of oil and gas properties -- 126,900 ------------ ------------ Total costs and expenses 1,025,018 1,310,340 ------------ ------------ Earnings (loss) before income tax expense and extraordinary item 114,278 (76,408) INCOME TAX EXPENSE Current 24,661 10,324 Deferred 31,527 7,278 ------------ ------------ Total income tax expense 56,188 17,602 ------------ ------------ Earnings (loss) before extraordinary item 58,090 (94,010) Preferred stock dividends 9,736 5,625 ------------ ------------ Earnings (loss) before extraordinary item applicable to common stockholders $ 48,354 (99,635) ============ ============ Earnings (loss) before extraordinary item per average common share outstanding - basic and diluted $ 0.60 (1.24) ============ ============ Weighted average common shares outstanding - basic 81,070 80,061 ============ ============ PRODUCTION DATA Oil (MBbls) 24,092 26,128 Gas (MMcf) 300,779 319,930 Natural gas liquids (MBbls) 6,908 7,129 MBoe 81,130 86,579
64 65 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Northstar Combination On June 29, 1998, Devon and Northstar Energy Corporation ("Northstar") announced they had entered into a definitive combination agreement subject to shareholder approval and certain other conditions. The combination of the two companies (the "Northstar Combination") was closed on December 10, 1998. At that date, Northstar became a wholly-owned subsidiary of Devon. Pursuant to the Northstar Combination, Northstar's common shareholders received approximately 16.1 million exchangeable shares (the "Exchangeable Shares") based on an exchange ratio of 0.235 Exchangeable Shares for each Northstar common share outstanding. The Exchangeable Shares were issued by Northstar, but are exchangeable at any time into Devon's common shares on a one-for-one basis. Prior to such exchange, the Exchangeable Shares have rights identical to those of Devon's common shares, including dividend, voting and liquidation rights. Between December 10, 1998 and December 31, 1999, approximately 11.4 million of the originally issued 16.1 million Exchangeable Shares had been exchanged for shares of Devon common stock. The Northstar Combination was accounted for under the pooling-of-interests method of accounting for business combinations. All operational and financial information contained herein includes the combined amounts for Devon and Northstar for all periods presented. During the fourth quarter of 1998, Devon recorded a pre-tax charge of $13.1 million ($9.7 million after tax) for direct costs related to the Northstar Combination. Morrison Transaction In March 1997, Northstar acquired all the outstanding common shares of Morrison Petroleums Ltd. ("Morrison"), an independent oil and gas producer also located in Alberta, Canada. Northstar acquired the Morrison common shares by issuing common shares of Northstar (the "Morrison Transaction"). The Northstar common shares received by the Morrison shareholders represented approximately 53% of the combined company's outstanding shares. Therefore, this transaction was accounted for as a reverse acquisition under U.S. generally accepted accounting principles. Accordingly, Northstar's results through March 31, 1997, which are combined with Devon's results in the accompanying consolidated financial statements, represent the historical results of Morrison, the "accounting acquirer." Because Northstar was the "legal acquirer," the financial results and other information for periods through March 31, 1997, are referred to as "Northstar's" results and information, even though they represent the historical results of Morrison. For periods subsequent to March 31, 1997, Northstar's results that are combined with Devon's results represent the historical results of Morrison, combined with Northstar's results after valuing Northstar's March 31, 1997, assets and liabilities at fair value, rather than historical book value. The estimated proved reserves added in the Morrison Transaction were 18.3 million barrels of oil, 213.5 billion cubic feet of natural gas and 2.9 million barrels of natural gas liquids. 65 66 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Also added in the Morrison Transaction were approximately 563,000 net acres of undeveloped leasehold. (The quantities of proved reserves stated in this paragraph are unaudited.) After giving effect to the Northstar Combination exchange ratio of 0.235, approximately 9.8 million Exchangeable Shares are deemed to have been issued in the Morrison Transaction with a total value of approximately $441.6 million. Also, approximately $111.3 million of liabilities were assumed and $128.5 million of additional deferred tax liabilities were recorded due to the tax-free nature of the Morrison Transaction to the Morrison shareholders. Excluding the $128.5 million of additional deferred tax liabilities, the total purchase price was allocated $435.2 million to proved oil and gas reserves, $37.3 million to undeveloped leasehold and $80.4 million to other assets acquired. Including the $128.5 million of deferred tax liabilities, the allocation was $527.9 million to proved oil and gas reserves, $43.5 million to undeveloped leasehold and $110.0 million to other assets. 3. SAN JUAN BASIN TRANSACTION At the beginning of 1995, Devon entered into a transaction (the "San Juan Basin Transaction") involving a volumetric production payment and repurchase option. The San Juan Basin Transaction allowed Devon to monetize tax credits earned from certain of its coal seam gas production in the San Juan Basin. During 1999, 1998 and 1997, the San Juan Basin Transaction added approximately $7.6 million, $8.4 million and $8.5 million, respectively, to Devon's gas revenues. Under the terms of the San Juan Basin Transaction, Devon has a repurchase option which it can exercise at anytime. Devon records a portion of the quarterly cash payments received pursuant to the San Juan Basin Transaction as a repurchase liability based upon the estimated eventual repurchase price. Devon has also received cash payments in exchange for agreeing not to exercise its repurchase option for specific periods of time. These payments have also been added to the repurchase liability. As a result, in addition to the cash flow recorded as revenues described in the previous paragraph, Devon also received $16.6 million, $6.8 million and $6.2 million in 1999, 1998 and 1997, respectively, which was added to the repurchase liability. At December 31, 1999, the repurchase liability totaled $37.6 million. This amount is included in other long-term liabilities in Devon's consolidated balance sheet. The additional gas revenues generated by the San Juan Basin Transaction will continue until December 31, 2002, unless Devon exercises its repurchase option earlier. 4. SUPPLEMENTAL CASH FLOW INFORMATION Cash payments for interest in 1999, 1998 and 1997 were approximately $63.3 million, $24.5 million and $16.7 million, respectively. Cash payments for federal, state and foreign income taxes in 1999, 1998 and 1997 were approximately $10.8 million, $14.2 million and $26.9 million, respectively. 66 67 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 The 1999 PennzEnergy merger and the 1997 Morrison Transaction involved non-cash consideration as presented below:
1999 1997 ------------ ------------ (IN THOUSANDS) Value of common stock issued $ 718,177 441,590 Value of preferred stock issued 150,000 -- Employee stock options assumed 18,295 -- Liabilities assumed 1,958,801 111,345 Deferred tax liability created 338,911 128,497 ------------ ------------ Fair value of assets acquired with non-cash consideration $ 3,184,184 681,432 ============ ============
During the fourth quarter of 1999, substantially all of the 6.5% Trust Convertible Preferred Securities were converted to Devon common stock (see Note 9). 5. ACCOUNTS RECEIVABLE The components of accounts receivable included the following:
DECEMBER 31, ------------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS) Oil, gas and natural gas liquids revenue accruals $ 138,562 46,360 52,974 Joint interest billings 54,158 23,636 25,283 Other 18,285 14,262 19,398 ---------- ---------- ---------- 211,005 84,258 97,655 Allowance for doubtful accounts (1,600) (400) (827) ---------- ---------- ---------- Net accounts receivable $ 209,405 83,858 96,828 ========== ========== ==========
67 68 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 6. PROPERTY AND EQUIPMENT Property and equipment included the following:
` DECEMBER 31, 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Oil and gas properties: Subject to amortization $ 4,589,986 2,413,376 2,157,104 Not subject to amortization: Acquired in 1999 115,866 -- -- Acquired in 1998 37,522 46,302 -- Acquired in 1997 36,077 51,961 60,399 Acquired prior to 1997 57,620 63,414 70,348 Accumulated depreciation, depletion and amortization (1,800,424) (1,498,075) (1,316,343) ----------- ----------- ----------- Net oil and gas properties 3,036,647 1,076,978 971,508 ----------- ----------- ----------- Other property and equipment 137,739 35,458 32,884 Accumulated depreciation and amortization (18,466) (11,508) (9,109) ----------- ----------- ----------- Net other property and equipment 119,273 23,950 23,775 ----------- ----------- ----------- Property and equipment, net of accumulated depreciation, depletion and amortization $ 3,155,920 1,100,928 995,283 =========== =========== ===========
Depreciation, depletion and amortization of property and equipment consisted of the following components:
YEAR ENDED DECEMBER 31, 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS) Depreciation, depletion and amortization of oil and gas properties $ 244,517 119,719 164,977 Depreciation and amortization of other property and equipment 7,160 3,964 3,566 Amortization of other assets 2,598 161 565 ---------- ---------- ---------- Total expense $ 254,275 123,844 169,108 ========== ========== ==========
68 69 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 7. LONG-TERM DEBT AND RELATED EXPENSES A summary of Devon's long-term debt is as follows:
DECEMBER 31, ----------------------------------------------------- 1999 ------------------------- PRO FORMA(A) ACTUAL 1998 1997 ----------- ----------- ----------- ----------- (IN THOUSANDS) Borrowings under credit facilities with banks $ 414,341 314,341 180,271 219,316 Debentures exchangeable into shares of Chevron Corporation common stock: 4.90% due August 15, 2008 443,807 443,807 -- -- 4.95% due August 15, 2008 316,506 316,506 -- -- Other debentures: 10.25% due November 1, 2005 250,000 250,000 -- -- 10.125% due November 15, 2009 200,000 200,000 -- -- Premium on debentures 37,467 37,467 -- -- Senior notes: 6.76% due July 19, 2005 -- 75,000 75,000 75,000 6.79% due March 2, 2009 -- 150,000 150,000 -- 7.03% due November 7, 2005 -- -- -- 60,000 ----------- ----------- ----------- ----------- 1,662,121 1,787,121 405,271 354,316 Less amount classified as current -- -- -- 48,979 ----------- ----------- ----------- ----------- Long-term debt $ 1,662,121 1,787,121 405,271 305,337 =========== =========== =========== ===========
Maturities of long-term debt as of December 31, 1999, excluding the $37.5 million of premiums, are as follows (in thousands):
PRO FORMA(a) ACTUAL ------------ --------- 2000 $ -- -- 2001 9,467 20,717 2002 84,467 20,717 2003 9,467 20,717 2004 159,467 220,717 2005 and thereafter 1,361,786 1,466,786 ------------ --------- Total $ 1,624,654 1,749,654 ============ ==========
(a) A discussion of pro forma debt outstanding is included later in this note. 69 70 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Credit Facilities With Banks On October 15, 1999, Devon entered into new unsecured long-term credit facilities aggregating $750 million (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $475 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced Devon's previous facilities that totaled $400 million. The $475 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $275 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until October 13, 2000 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt borrowed under the Tranche B facility matures two years and one day following the end of the Tranche B Revolving Period. At December 31, 1999, there were $200 million in borrowings from the $475 million U.S. Facility, all of which was borrowed under the Tranche A facility. Devon may borrow funds under the $275 million Canadian Facility until October 13, 2000 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 45 and 90 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semi-annual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. At December 31, 1999, there was $114.3 million borrowed under the $275 million Canadian facility. Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly. The average interest rate on the $314.3 million of debt outstanding at December 31, 1999, was 5.9%. The average interest rate on bank debt outstanding under the previous facilities at December 31, 1998 and 1997 was 5.9% and 4.8%, respectively. The agreements governing the Credit Facilities contain certain covenants and restrictions, including a maximum debt-to-capitalization ratio. At December 31, 1999, Devon was in compliance with such covenants and restrictions. Exchangeable Debentures The exchangeable debentures consist of $443.8 million of 4.90% debentures and $316.5 million of 4.95% debentures. The exchangeable debentures were issued on August 3, 1998, mature August 15, 2008, and are callable beginning August 15, 2000. The exchangeable 70 71 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 debentures are exchangeable at the option of the holders at any time prior to maturity, unless previously redeemed, for shares of Chevron Corporation common stock. In lieu of delivering Chevron Corporation common stock, Devon may, at its option, pay to any holder an amount of cash equal to the market value of the Chevron Corporation common stock to satisfy the exchange request. However, at maturity, the holders will receive an amount at least equal to the face value of the debt outstanding - either in cash or in a combination of cash and Chevron Corporation common stock. As of December 31, 1999, Devon beneficially owned approximately 7.1 million shares of Chevron Corporation 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 9.3283 shares of Chevron Corporation common stock, an exchange rate equivalent to $107 7/32 per share of Chevron 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. The fair value approximated the face value of the exchangeable debentures. As a result, no premium or discount was recorded on these exchangeable debentures. Other Debentures The 10.25% and 10.125% debentures were assumed as part of the PennzEnergy merger. 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 $250 million of 10.25% debentures and $200 million of 10.125% debentures, respectively. The premiums are being amortized using the effective interest method. Senior Notes Northstar issued the 6.76% notes in a private placement in 1995. The notes were unsecured and were payable in five annual installments of $15 million each beginning in 2001. In mid-January 2000, Devon retired these notes. See the "Pro Forma" section below. Northstar issued the 6.79% notes in a private placement in 1998. The notes were unsecured and were payable in three annual installments of $50 million each beginning in 2007. Proceeds from these notes were partially used to retire the $60 million of 7.03% notes referred to in the preceding table of long-term debt. In mid-January 2000, Devon retired these notes. See the "Pro Forma" section below. The agreements governing the Senior Notes contained certain covenants and restrictions specific to Northstar, including maintenance of certain debt-to-capitalization and debt-to-EBITDA ratios and a minimum tangible net worth as well as restrictions on additional 71 72 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 borrowings. At December 31, 1999, Northstar was in compliance with such covenants and restrictions. Pro Forma In January 2000, Devon used excess cash of $75 million, together with borrowings of $150 million under its Credit Facilities, to retire the $225 million of Senior Notes outstanding as of December 31, 1999. Also in January 2000, Devon used an additional $50 million of excess cash to pay down borrowings under Tranche A of the U.S. Facility. The result of these early 2000 transactions left $414.3 million outstanding under the Credit Facilities. Of this amount, $150 million was borrowed under Tranche A of the U.S. Facility, $75 million was borrowed under Tranche B of the U.S. Facility and $189.3 million was borrowed under the Canadian Facility. The average interest rate on the $414.3 million of pro forma debt outstanding under the Credit Facilities was 5.9%. Interest Expense Following are the components of interest expense for the years 1999, 1998 and 1997:
1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS) Interest based on debt outstanding $ 66,164 21,814 14,345 Amortization of premium on debentures (1,328) -- -- Facility and agency fees 930 632 598 Amortization of capitalized loan costs 783 156 118 Penalty on early retirement of debt -- -- 3,323 Hedging gains -- (188) (410) Other 364 218 814 ---------- ---------- ---------- Total interest expense $ 66,913 22,632 18,788 ========== ========== ==========
Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt The fixed-rate Senior Notes referred to in the first table of this note were payable by Northstar. However, the notes were 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 issued to the dates of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent of the debt were required to be included in determining net earnings for the period in which the exchange rate changed. The rate of conversion of Canadian dollars to U.S. dollars increased in 1999 and declined in 1998 and 1997. Therefore, $13.2 million of reduced expense was recorded in 1999, and $16.1 million and $5.9 million of increased expenses were recorded in 1998 and 1997, respectively. 72 73 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 8. INCOME TAXES At December 31, 1999, Devon had the following carryforwards available to reduce future income taxes:
YEARS OF CARRYFORWARD TYPES OF CARRYFORWARD EXPIRATION AMOUNTS ---------- ------------- (IN THOUSANDS) Net operating loss - U.S. federal 2008 - 2014 $309,098 Net operating loss - various states 2000 - 2013 $157,801 Net operating loss - Canada 2000 - 2005 $ 85,254 Minimum tax credits Indefinite $ 69,647
All of the carryforward amounts shown above have been utilized for financial purposes to reduce deferred taxes. The earnings (loss) before income taxes and the components of income tax expense (benefit) for the years 1999, 1998 and 1997 were as follows:
YEAR ENDED DECEMBER 31, 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS) Earnings (loss) before income taxes: U.S $ 103,399 (95,750) 106,665 Canada 57,402 19,958 (580,498) Other (1,079) -- -- ---------- ---------- ---------- Total $ 159,722 (75,792) (473,833) ========== ========== ========== Current income tax expense: U.S. federal 18,844 4,801 18,659 Various states 2,904 911 2,521 Canada 2,908 1,975 5,677 Other -- -- -- ---------- ---------- ---------- Total current tax expense 24,656 7,687 26,857 ---------- ---------- ---------- Deferred income tax expense (benefit): U.S. federal 14,514 (29,524) 17,025 Various states (495) (4,836) 1,578 Canada 26,654 11,166 (219,302) Other (163) -- -- ---------- ---------- ---------- Total deferred tax expense (benefit) 40,510 (23,194) (200,699) ---------- ---------- ---------- Total income tax expense (benefit) $ 65,166 (15,507) (173,842) ========== ========== ==========
73 74 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) before income taxes as a result of the following:
YEAR ENDED DECEMBER 31, ------------------------- 1999 1998 1997 ---- ---- ---- U.S. statutory tax (benefit) rate 35% (35)% (35)% Non-deductible expenses 3 15 -- Nonconventional fuel source credits (3) (4) -- State income taxes 1 (3) -- Taxation on foreign operations 6 8 (2) Other (1) (1) -- ---- ---- ---- Effective income tax (benefit) rate 41% (20)% (37)% ==== ==== ====
The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 1999, 1998 and 1997 are presented below:
DECEMBER 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS) Deferred tax assets: Net operating loss carryforwards $ 156,622 21,818 21,076 Minimum tax credit carryforwards 69,647 -- -- Production payments 21,527 19,105 18,504 Long-term debt 17,583 -- -- Other 45,018 3,188 7,173 ---------- ---------- ---------- Total gross deferred tax assets 310,397 44,111 46,753 Less valuation allowance 100 100 100 ---------- ---------- ---------- Net deferred tax assets 310,297 44,011 46,653 ---------- ---------- ---------- Deferred tax liabilities: Property and equipment, principally due to differences in depreciation, and the expensing of intangible drilling costs for tax purposes (492,756) (76,156) (76,523) Chevron Corporation common stock (172,631) -- -- Other (30,889) (469) (1,521) ---------- ---------- ---------- Total deferred tax liabilities (696,276) (76,625) (78,044) ---------- ---------- ---------- Net deferred tax liability $ (385,979) (32,614) (31,391) ========== ========== ==========
As shown in the above schedule, Devon has recognized $310.3 million of net deferred tax assets as of December 31, 1999. Such amount consists primarily of $226.3 million of various 74 75 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 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 2008, state net operating loss carryforwards which expire primarily between 2000 and 2013, Canadian carryforwards which expire primarily between 2000 and 2005, and 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 2000 and 2006. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, 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. A $0.1 million valuation allowance has been recorded at December 31, 1999, related to depletion carryforwards acquired in a 1994 merger. The $21.5 million of deferred tax assets related to production payments is offset by a portion of the deferred tax liability related to the excess financial basis of property and equipment. The income tax accounting for the San Juan Basin Transaction described in Note 3 differs from the financial accounting treatment. For income tax purposes, a gain from the conveyance of the properties was realized, and the present value of the production payments to be received was recorded as a note receivable. For presentation purposes, the $21.5 million represents the tax effect of the difference in accounting for the production payment, less the effect of the taxable gain from the transaction which is being deferred and recognized on the installment basis for income tax purposes. 9. TRUST CONVERTIBLE PREFERRED SECURITIES On July 10, 1996, Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% trust convertible preferred securities (the "TCP Securities"). Devon Financing Trust issued 2,990,000 shares of the TCP Securities at $50 per share with a maturity date of June 15, 2026. Each TCP Security was convertible at the holder's option into 1.6393 shares of Devon common stock, which equates to a conversion price of $30.50 per share of Devon common stock. Devon Financing Trust invested the $149.5 million of proceeds in 6.5% convertible junior subordinated debentures issued by Devon (the "Convertible Debentures"). In turn, Devon used the net proceeds from the issuance of the Convertible Debentures to retire debt outstanding under its credit lines. On October 27, 1999, Devon issued notice to the holders of the TCP Securities that it was 75 76 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 exercising its right to redeem such securities on November 30, 1999. Substantially all of the holders of the TCP Securities elected to exercise their conversion rights instead of receiving the redemption cash value. As a result, all but 950 shares of the TCP Securities were converted into approximately 4.9 million shares of Devon common stock. The redemption price for the 950 shares not converted was $52.275 per share, or $50,000 total, which included a 4.55% premium as required under the terms of the TCP Securities. Devon owned all the common securities of Devon Financing Trust. As such, the accounts of Devon Financing Trust were included in Devon's consolidated financial statements after appropriate eliminations of intercompany balances and transactions. The distributions on the TCP Securities were recorded as a charge to pre-tax earnings on Devon's consolidated statements of operations, and such distributions were deductible by Devon for income tax purposes. 10. STOCKHOLDERS' EQUITY The authorized capital stock of Devon consists of 400 million shares of common stock, par value $.10 per share (the "Common Stock"), 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. 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. In late September and early October 1999, Devon received $402.7 million from the sale of approximately 10.3 million shares of its common stock in a public offering. The price to the public for these shares was $40.50 per share. Net of underwriters' discount and commissions, Devon received $38.98 per share. Devon paid approximately $0.8 million of expenses related to the equity offering, and these costs were recorded as reductions of additional paid-in capital. As discussed in Note 2, there were approximately 21.5 million shares of Devon common stock issued on August 17, 1999, in connection with the PennzEnergy merger. Also, as discussed in Note 2, there were 16.1 million Exchangeable Shares issued on December 10, 1998, in connection with the Northstar Combination. As of year-end 1999, 11.4 million of the Exchangeable Shares had been exchanged for shares of Devon's common stock. The Exchangeable Shares have rights identical to those of Devon's common stock and are exchangeable at any time into Devon's common stock on a one-for-one basis. Devon's Board of Directors has designated 1.0 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the "Series A Junior Preferred Stock") in connection with the 76 77 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 adoption of the share rights plan described later in this note. At December 31, 1999, 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 $10 or 100 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 100 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. Stock Option Plans Devon has outstanding stock options issued to key management and professional employees under three stock option plans adopted in 1988, 1993 and 1997 (the "1988 Plan," the "1993 Plan" and the "1997 Plan"). Options granted under the 1988 Plan and 1993 Plan remain exercisable by the employees owning such options, but no new options will be granted under these plans. At December 31, 1999, there were 189,000 and 740,500 options outstanding under the 1988 Plan and the 1993 Plan, respectively. On May 21, 1997, Devon's stockholders adopted the 1997 Plan and reserved two million shares of Common Stock for issuance thereunder. On December 9, 1998, Devon's stockholders voted to increase the reserved shares to three million. On August 17, 1999, Devon's stockholders voted to increase the reserved shares to six million. The exercise price of stock options granted under the 1997 Plan may not be less than the estimated fair market value of the stock at the date of grant, plus 10% if the grantee owns or controls more than 10% of the total voting stock of Devon prior to the grant. Options granted are exercisable during a period established for each grant, which period may not exceed 10 years from the date of grant. Under the 1997 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 1997 Plan is administered by a committee comprised of non-management members of the Board of Directors. The 1997 Plan expires on April 25, 2007. As of December 31, 1999, there were 2,142,150 options outstanding under the 1997 Plan. There were 3,725,550 options available for future grants as of December 31, 1999. In addition to the stock options outstanding under the 1988 Plan, 1993 Plan and 1997 Plan, there were 2,081,124 and 226,571 stock options outstanding at the end of 1999 that were assumed as part of the PennzEnergy merger and the Northstar Combination, respectively. PennzEnergy and Northstar had granted these options prior to the PennzEnergy merger and the Northstar Combination. As part of the PennzEnergy merger and the Northstar Combination, the options were assumed by Devon and converted to Devon options at the exchange rate of 0.4475 and 0.235 Devon options for each PennzEnergy and Northstar option, respectively. 77 78 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 A summary of the status of Devon's stock option plans as of December 31, 1997, 1998 and 1999, and changes during each of the years then ended, is presented below.
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ---------------------------- --------------------------- WEIGHTED WEIGHTED AVERAGE AVERAGE NUMBER EXERCISE NUMBER EXERCISE OUTSTANDING PRICE EXERCISABLE PRICE ------------ ------------ ------------ ------------ Balance at December 31, 1996 2,025,783 $ 27.305 1,112,049 $ 24.556 ============ ============ Options assumed in the Morrison Transaction 732,041 $ 36.260 Options granted 691,767 $ 32.515 Options exercised (486,918) $ 26.444 Options forfeited (332,183) $ 37.540 ------------ Balance at December 31, 1997 2,630,490 $ 29.276 1,415,909 $ 26.483 ============ ============ Options granted 1,260,397 $ 31.230 Options exercised (134,295) $ 21.087 Options forfeited (300,900) $ 32.730 ------------ Balance at December 31, 1998 3,455,692 $ 28.995 2,635,727 $ 28.793 ============ ============ Options granted 1,148,000 $ 30.817 Options assumed in the PennzEnergy merger 2,081,894 $ 55.643 Options exercised (924,467) $ 27.392 Options forfeited (381,774) $ 34.841 ------------ Balance at December 31, 1999 5,379,345 $ 39.555 4,185,547 $ 42.020 ============ ============ ============
The weighted average fair values of options granted during 1999, 1998 and 1997 were $10.23, $10.72 and $10.12, 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 1999, 1998 and 1997, respectively: risk-free interest rates of 6.0%, 4.9% and 6.0%; dividend yields of 0.6%, 0.5% and 0.1%; expected lives of 4, 4 and 4 years; and volatility of the price of the underlying common stock of 34.2%, 33.9% and 30.7%. 78 79 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 The following table summarizes information about Devon's stock options which were outstanding, and those which were exercisable, as of December 31, 1999:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE --------------------------------------- ------------------------ WEIGHTED WEIGHTED WEIGHTED RANGE OF AVERAGE AVERAGE AVERAGE EXERCISE NUMBER REMAINING EXERCISE NUMBER EXERCISE PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE - - - - - - - - -------------- ----------- --------- ---------- ----------- ---------- $ 8.375-$25.440 717,466 4.4 years $ 21.773 702,600 $ 21.713 $26.291-$29.850 734,622 5.5 years $ 29.001 616,064 $ 28.977 $30.938-$33.606 1,441,919 8.9 years $ 31.257 410,378 $ 31.843 $35.582-$39.437 977,694 8.1 years $ 36.875 950,411 $ 36.863 $40.125-$58.840 813,250 6.0 years $ 52.868 811,700 $ 52.891 $63.433-$92.781 694,394 5.2 years $ 74.504 694,394 $ 74.504 ---------- ---------- 5,379,345 6.8 years $ 39.555 4,185,547 $ 42.020 ========== ==========
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 1999, 1998 and 1997 pro forma net earnings (loss) and pro forma net earnings (loss) per share would have differed from the amounts actually reported as shown in the following table. The pro forma amounts shown below do not include the effects of stock options granted prior to January 1, 1995.
YEAR ENDED DECEMBER 31, ------------------------------------- 1999 1998 1997 ---- ---- ---- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Net earnings (loss) available to common shareholders: As reported $ 90,905 (60,285) (299,991) Pro forma $ 84,095 (72,770) (306,992) Net earnings (loss) per share available to common shareholders: As reported: Basic $ 1.51 (1.25) (6.38) Diluted $ 1.46 (1.25) (6.38) Pro forma: Basic $ 1.40 (1.50) (6.52) Diluted $ 1.36 (1.50) (6.52)
79 80 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Share Rights Plan Under Devon's share rights plan, stockholders have 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 $75.00, 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 April 16, 2005. The rights may be redeemed by Devon for $.01 per right until the rights become exercisable. 11. FINANCIAL INSTRUMENTS The following table presents the carrying amounts and estimated fair values of Devon's financial instruments at December 31, 1999, 1998 and 1997.
1999 1998 1997 -------------------------- --------------------- ------------------------ CARRYING FAIR CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE ---------- ---------- -------- -------- --------- --------- (IN THOUSANDS) Investments $ 625,181 625,181 1,930 1,930 2,409 5,125 Oil and gas price hedge agreements $ -- (11,525) -- 1,988 -- 3,569 Foreign exchange hedge agreements $ -- (2,535) -- (9,310) -- (5,038) Long-term debt (including current portion) $(1,787,121) (1,772,934) (405,271) (421,675) (354,316) (360,294) TCP Securities $ -- -- (149,500) (171,400) (149,500) (218,800)
The following methods and assumptions were used to estimate the fair values of the financial instruments in the above table. None of Devon's financial instruments are held for trading purposes. The carrying values of cash and cash equivalents, 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, 1999, 1998 and 1997. 80 81 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Investments - The fair values of investments are primarily based on quoted market prices. Oil and Gas Price Hedge Agreements - The fair values of the oil and gas price hedges are based on either (a) quotes obtained from the counterparty to the hedge agreement or (b) quotes provided by brokers. Foreign Exchange Hedge Agreements - The fair values of the foreign exchange agreements are based on quotes obtained from brokers. Long-term Debt - The fair values of the fixed-rate long-term debt have been estimated 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. TCP Securities - The fair values of the TCP Securities are based on quoted market prices provided by brokers. The following table covers Devon's notional volumes and pricing on open natural gas hedging instruments as of December 31, 1999:
YEAR OF PRODUCTION --------------------------------- 2000 2001 2002 ------ ------ ----- Volumes (billion British thermal units) 18,215 12,661 2,656 Average price to be received $1.82 1.87 1.83
The floating reference prices which Devon will pay the counterparties to the above gas price hedging instruments include several index prices based upon the area of the gas production that is hedged. For the hedged Canadian gas production, these reference prices are primarily based on index prices published by the Alberta Energy Company ("AECO"). For the hedged U.S. production, the reference prices are primarily based on index prices published by "Inside FERC" for the Rocky Mountains and San Juan Basin. Devon has certain foreign currency hedging instruments that offset a portion of the exposure to currency fluctuations on Canadian oil sales that are based on U.S. dollar prices. Gains and losses recognized on these foreign currency hedging instruments are included as increases or decreases to realized oil sales. As of December 31, 1999, Devon had open foreign currency hedging instruments in which it will sell $30 million in 2000 at 81 82 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 average Canadian-to-U.S. dollar exchange rates of $0.7265. A portion of these hedging instruments can be extended an additional year at the option of the counterparty. If such options are exercised, Devon will sell an additional $10 million in 2001 at average Canadian-to-U.S. dollar exchange rates of $0.7102. Under these agreements, Devon will buy the same amount of dollars in each year at the floating exchange rate. Devon's 1999, 1998 and 1997 consolidated balance sheets include deferred revenues of $0.4 million, $1.0 million and $3.8 million, respectively, for gains realized on the early termination of commodity and foreign currency hedging instruments in prior years. These deferred gains as of the end of 1999 will be recognized as oil and gas sales over periods ranging from ten months to one year as the hedged oil and gas production occurs. 12. RETIREMENT PLANS Devon has non-contributory defined benefit retirement plans (the "Basic Plans") which include U.S. employees meeting certain age and service requirements. The benefits are based on the employee's years of service and compensation. Devon's funding policy is to contribute annually the maximum amount that can be deducted for federal income tax purposes. Rights to amend or terminate the Basic Plans are retained by Devon. Devon also has separate defined benefit retirement plans (the "Supplementary Plans") which are non-contributory and include only certain employees whose benefits under the Basic Plans are limited by income tax regulations. The Supplementary Plans' benefits are based on the employee's years of service and compensation. Devon's funding policy for the Supplementary Plans is to fund the benefits as they become payable. Rights to amend or terminate the Supplementary Plans are retained by Devon. Additionally, Devon assumed responsibility for the PennzEnergy sponsored defined benefit postretirement plans, which are unfunded, and cover substantially all of the former PennzEnergy employees who remained with Devon. Devon did not extend these benefits to other employees. The plans provide medical and life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. The accounting for the health care plan anticipates future cost-sharing changes that are consistent with Devon's expressed intent to increase, where possible, contributions for future retirees. Furthermore, future contributions for both current and future salaried retirees have been limited to 200% of the 1992 retiree premium rates. Retirees will be required to absorb all future cost increases over that limit. 82 83 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 The following table sets forth the plans' benefit obligations, plan assets, reconciliation of funded status, amounts recognized in the consolidated balance sheets and the actuarial assumptions used as of December 31:
OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS ---------------------------------------- -------------------- 1999 1998 1997 1999 ---------- ---------- ---------- ---------- (IN THOUSANDS) Change in benefit obligation: Benefit obligation at beginning of year $ 15,141 11,659 8,029 $ -- Service cost 2,537 985 706 138 Interest cost 3,164 935 747 649 Amendments -- 293 -- -- PennzEnergy merger 84,651 -- -- 27,859 Actuarial (loss) gain (1,525) 1,773 1,463 -- Benefits paid (1,699) (504) (349) (886) Establishment of new plan -- -- 1,063 -- ---------- ---------- ---------- ---------- Benefit obligation at end of year 102,269 15,141 11,659 27,760 ---------- ---------- ---------- ---------- Change in plan assets: Fair value of plan assets at beginning of year 6,331 6,036 5,022 -- Actual return on plan assets 8,808 (87) 366 -- PennzEnergy merger 104,181 -- -- -- Employer contributions 1,173 886 997 886 Benefits paid (1,699) (504) (349) (886) ---------- ---------- ---------- ---------- Fair value of plan assets at end of year 118,794 6,331 6,036 -- ---------- ---------- ---------- ---------- Funded status 16,525 (8,810) (5,623) (27,760) Unrecognized net actuarial (gain) loss (2,223) 4,730 2,448 -- Unrecognized prior service cost 1,566 1,822 1,973 -- ---------- ---------- ---------- ---------- Net amount recognized $ 15,868 (2,258) (1,202) (27,760) ========== ========== ========== ========== The net amounts recognized in the consolidated balance sheets consist of: Prepaid (accrued) benefit cost $ 15,868 (2,258) (1,202) $ (27,760) Additional minimum liability (3,110) (2,987) (2,557) -- Intangible asset 1,537 1,808 2,557 -- Accumulated other comprehensive loss 1,573 1,179 -- -- ---------- ---------- ---------- ---------- Net amount recognized $ 15,868 (2,258) (1,202) $ (27,760) ========== ========== ========== ========== Assumptions: Discount rate 7.25% 6.50% 7.00% 7.25% Expected return on plan assets 8.00% 8.50% 8.50% N/A Rate of compensation increase 5.00% 5.00% 5.00% N/A
83 84 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 The benefit obligation for the defined benefit pension plans with benefit obligations in excess of assets was $8.0 million as of December 31, 1999. No plan assets existed for these plans at December 31, 1999. Net periodic benefit cost included the following components:
OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS ----------------------------------- -------------------- 1999 1998 1997 1999 --------- --------- --------- --------- (IN THOUSANDS) Service cost $ 2,537 985 706 $ 138 Interest cost 3,164 935 747 649 Expected return on plan assets (3,700) (532) (445) -- Amortization of prior service cost 256 256 194 -- Recognized net actuarial loss 320 111 59 -- --------- --------- --------- --------- Net periodic benefit cost $ 2,577 1,755 1,261 $ 787 ========= ========= ========= =========
For measurement purposes, a 7% annual rate of increase in the per capita cost of covered health care benefits was assumed in 2000. The rate was assumed to decrease on a pro-rata basis annually to 5% in the year 2002 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one percentage-point change in assumed health care cost trend rates would have the following effects:
ONE-PERCENTAGE ONE-PERCENTAGE POINT INCREASE POINT DECREASE -------------- -------------- (IN THOUSANDS) Effect on total of service and interest cost components for 1999 $ 24 $ (26) Effect on year-end 1999 postretirement benefit obligation 809 (916)
As a result of the PennzEnergy merger, Devon assumed 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 which are accounted for under SFAS No. 112, "Employer's Accounting for Postemployment Benefits." The accrued postemployment benefit liability was approximately $2.5 million at the end of 1999. 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 $2.7 million, $1.0 million and $0.5 million for the years ended December 31, 1999, 1998 and 1997, respectively. Devon has defined contribution plans for its Canadian employees. Devon contributes between 6% and 10% of the employee's base compensation, depending upon the employee's classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada). 84 85 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes an amount equal to 2% of the base salary of each employee. The employees may elect to contribute up to 4% of their salary. If such employee contributions are made, they are matched by additional Devon contributions. During the years 1999, 1998 and 1997, Devon's combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $1.9 million, $1.8 million and $1.2 million, respectively. 13. 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 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. 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 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 the PennzEnergy merger 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, 1999, Devon's consolidated balance sheet included $6.7 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. 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) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be 85 86 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material. Ramco Dispute In October 1995, subsidiaries of Devon acquired in the PennzEnergy merger filed an action, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States District Court for the Southern District of Texas, Houston Division, against Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively "Ramco"). The underlying dispute involves Ramco's asserted claim to an interest in the Karabakh prospect, an oil and gas field located in the territorial waters of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the litigation, the operator of the Karabakh prospect determined that the hydrocarbon accumulation tested by three exploratory wells was not commercial. The federal suit sought to compel Ramco to arbitrate certain disputes that have arisen between it and the Devon plaintiffs pursuant to the Federal Arbitration Act and the Convention on the Recognition and Enforcement of Foreign Arbitral Awards. After the filing of the federal action, the Devon plaintiffs filed an Original Petition for Declaration Relief in the 281st Judicial District Court of Harris County, Texas. The state suit, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is expressly conditioned upon a determination in the federal suit that the disputes between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a declaration that the Devon plaintiffs have not breached any agreements with Ramco, and do not owe and/or have not breached any fiduciary or other legal duty to Ramco including, without limitation, a duty of good faith and fair dealing. In November 1995, Ramco asserted a counterclaim in the state court action, asserting breach of contract and breach of fiduciary duties. The counterclaim seeks a declaratory judgment granting Ramco a participation interest in the Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees, court costs and other unspecified relief. The judge in the federal suit granted in part the plaintiffs' motion to compel arbitration and ordered arbitration to be held in New York, New York. The United States Court of Appeals for the Fifth Circuit generally affirmed the ruling of the judge in the federal suit and the Devon plaintiffs initiated arbitration. The parties have been engaged in settlement discussions and the selection of arbitrators has been suspended by agreement of the parties pending the outcome of the settlement discussions. Royalty Matters More than 30 oil companies, including Devon as a result of the PennzEnergy merger, are involved in disputes in which it is alleged that the oil companies and related parties have underpaid holders of royalty interests, overriding royalty interests and working interests in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana. Certain parties to the federal litigation have entered into a global settlement agreement which provides for a conditional nationwide settlement, subject to opt-outs, of 86 87 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 the crude oil royalty, overriding royalty and working interest claims of all members of the settlement class, including claims in the federal litigation and in numerous other individual and class action cases pending throughout the United States. The federal court held a fairness hearing April 5, 1999, and the settlement was approved. The Amended Final Judgment was entered September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon is a party to the settlement agreement, which explicitly refutes an admission of liability, but was entered into to avoid expensive and protracted litigation. Also, pending is a separate suit in federal court in Texas alleging that more than 30 major oil companies, including Devon as a result of the PennzEnergy merger, underpaid royalties to the United States in connection with crude oil produced from United States owned and/or controlled lands since 1986. The claims were filed by private litigants under the federal False Claims Act, and after investigation, the United States served notice of its intent to intervene as to certain defendants. Devon has reached an agreement in principle with the United States and the private litigants to settle the claims made in the case. Devon believes that it has acted reasonably and paid royalties in good faith, but has entered into the settlement agreement, which explicitly refutes an admission of liability, to avoid expensive and protracted litigation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such settlement of the royalty matters. Maersk Rig Contracts In December 1997, Pennzoil Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the PennzEnergy merger, entered into a contract ("Contract #1") with Maersk Jupiter Drilling, S.A. ("Maersk") for the provision of a rig for drilling services relative to the anticipated drilling program associated with Devon's Block 68/79, Lake Maracaibo, Venezuela. The rig to be provided by Maersk was to be assembled and delivered to the Lake Maracaibo area and placed in service in October 1998. The term of Contract #1 was to October 1, 2001. A companion contract ("Contract #2") with Maersk for a second rig with a similar term for use in conjunction with the Block 70/80 drilling program was also executed by PVC's working interest partner in that Block. With execution of Contract #1, construction of the rig destined for Block 68/79 proceeded until completion thereof. In October 1998, Maersk advised that it intended to commence mobilization of the rig to Lake Maracaibo. However, during the period of rig construction, changes had occurred in the scope and timing of the drilling program anticipated for Block 68/79, resulting in significant reduction of the need for drilling services originally envisioned in Contract #1. PVC instructed Maersk to cease mobilization and to stack the rig in Brownsville, Texas, where it currently remains. The rig built for Contract #2 was delivered to Lake Maracaibo where it performed an abbreviated drilling program for both Blocks 68/79 and 70/80. It is currently stacked in Lake Maracaibo. 87 88 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 While both Contract #1 and #2 provide for early termination, the charge for such termination is established in each contract as the "Contract Standby Rate" which is currently estimated at $42,000 per day, per contract, with certain escalation factors for the balance of the term of each. Representatives of PVC and Maersk are engaged in negotiations relative to termination/settlement of both Contract #1 and Contract #2. As of December 31, 1999, Devon's consolidated balance sheet included accrued liabilities, reflected in "Other liabilities," for the expected cost to terminate/settle both Contract #1 and Contract #2. This liability was recorded at the time of the PennzEnergy merger. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such termination/settlement of both Contract #1 and Contract #2. Operating Leases The following is a schedule by year of future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1999:
YEAR ENDING DECEMBER 31, (IN THOUSANDS) ------------------------ 2000 $ 7,221 2001 4,285 2002 2,730 2003 2,462 2004 2,372 Thereafter 6,331 ------- Total minimum lease payments required $25,401 =======
Total rental expense for all operating leases is as follows for the years ended December 31:
(IN THOUSANDS) 1999 $6,904 1998 $3,119 1997 $2,619
14. 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. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less 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. 88 89 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 As of September 30, 1998, the carrying value of Devon's domestic properties, less deferred income taxes, exceeded the full cost ceiling by $88 million. Accordingly, a $126.9 million pre-tax reduction of the carrying value of such properties was recorded in the third quarter of 1998. This reduction was partially offset by a related $38.9 million deferred income tax benefit, resulting in an after-tax charge of $88 million. As of December 31, 1997, the carrying value of Northstar's Canadian oil and gas properties, less deferred income taxes, exceeded the full cost ceiling by $397.9 million. Accordingly, a $625.5 million pre-tax reduction of the carrying value of such properties was recorded in the fourth quarter of 1997. This reduction was partially offset by a related $227.6 million deferred income tax benefit, resulting in an after-tax charge of $397.9 million. 15. OIL AND GAS OPERATIONS Costs Incurred The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities:
TOTAL YEAR ENDED DECEMBER 31, --------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 1,966,669 135,167 510,331 Deferred income taxes -- 21,382 94,822 ----------- ----------- ----------- Total proved, including deferred income taxes $ 1,966,669 156,549 605,153 =========== =========== =========== Unproved, excluding deferred income taxes: Business combinations 83,505 5,278 37,261 Other acquisitions 22,383 37,027 13,075 Deferred income taxes -- 661 6,082 ----------- ----------- ----------- Total unproved, including deferred income taxes $ 105,888 42,966 56,418 =========== =========== =========== Exploration costs $ 70,506 85,614 54,640 Development costs $ 124,226 152,105 162,244
89 90 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DOMESTIC --------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 1,635,637 27,349 10,891 ----------- Deferred income taxes -- -- 2,084 ----------- ----------- ----------- Total proved, including deferred income taxes $ 1,635,637 27,349 12,975 =========== =========== =========== Unproved, excluding deferred income taxes: Business combinations 81,755 -- -- Other acquisitions 13,228 26,764 7,582 Deferred income taxes -- -- (100) ----------- ----------- ----------- Total unproved, including deferred income taxes $ 94,983 26,764 7,482 =========== =========== =========== Exploration costs $ 29,771 35,686 18,326 Development costs $ 92,195 76,986 79,943
CANADA --------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 29,532 107,818 499,440 Deferred income taxes -- 21,382 92,738 ----------- ----------- ----------- Total proved, including deferred income taxes $ 29,532 129,200 592,178 =========== =========== =========== Unproved, excluding deferred income taxes: Business combinations -- 5,278 37,261 Other acquisitions 9,155 10,263 5,493 Deferred income taxes -- 661 6,182 ----------- ----------- ----------- Total unproved, including deferred income taxes $ 9,155 16,202 48,936 =========== =========== =========== Exploration costs $ 37,197 49,928 36,314 Development costs $ 29,811 75,119 82,301
INTERNATIONAL --------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 301,500 -- -- ----------- Deferred income taxes -- -- -- ----------- ----------- ----------- Total proved, including deferred income taxes $ 301,500 -- -- =========== =========== =========== Unproved, excluding deferred income taxes: Business combinations 1,750 -- -- Other acquisitions -- -- -- Deferred income taxes -- -- -- ----------- ----------- ----------- Total unproved, including deferred income taxes $ 1,750 -- -- =========== =========== =========== Exploration costs $ 3,538 -- -- Development costs $ 2,220 -- --
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 90 91 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $18.7 million, $9.6 million and $7.5 million in the years 1999, 1998 and 1997, respectively. Due to the tax-free nature of the PennzEnergy merger, additional deferred tax liabilities of $338.9 million were recorded in 1999 and allocated to goodwill. During 1997, various uncertainties that existed at year-end 1996 regarding the tax basis and liabilities assumed in the acquisition of Kerr-McGee Corporation's North American onshore oil and gas exploration and production business and properties ("KMG-NAOS") were resolved. This resulted in an additional $5.5 million being allocated in 1997 to the proved properties acquired in the 1996 KMG-NAOS transaction. Of this amount, $3.1 million was for liabilities assumed and $2.4 million was for additional deferred tax liabilities created. This additional $5.5 million is included in the preceding table of costs incurred in 1997. The resolution of the uncertainties also resulted in a reduction of $0.1 million in 1997 to the deferred tax liabilities originally allocated in 1996 to the KMG-NAOS unproved properties. Due to the tax-free nature of the Morrison Transaction, additional deferred tax liabilities of $128.5 million were recorded in 1997. Of this amount, $92.7 million was allocated to proved oil and gas properties and $6.2 million was allocated to unproved properties. The remaining amount of $29.6 million was allocated to non-oil and gas properties. 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. 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 and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences. 91 92 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
TOTAL -------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------- 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 715,503 369,660 452,104 Production and operating expenses (189,903) (127,400) (120,124) Depreciation, depletion and amortization (244,517) (119,719) (164,977) Amortization of goodwill (16,111) -- -- Reduction of carrying value of oil and gas properties -- (126,900) (625,514) Income tax (expense) benefit (112,684) (19,385) 159,511 ---------- ---------- ---------- Results of operations for oil and gas producing activities $ 152,288 (23,744) (299,000) ========== ========== ========== Depreciation, depletion and amortization per equivalent barrel of production $ 4.65 3.32 4.86 ========== ========== ==========
DOMESTIC -------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------- 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 519,502 208,630 273,860 Production and operating expenses (137,209) (77,829) (75,758) Depreciation, depletion and amortization (179,941) (76,327) (73,091) Amortization of goodwill (16,106) -- -- Reduction of carrying value of oil and gas properties -- (126,900) -- Income tax (expense) benefit (74,614) 18,230 (44,648) ---------- ---------- ---------- Results of operations for oil and gas producing activities $ 111,632 (54,196) 80,363 ========== ========== ========== Depreciation, depletion and amortization per equivalent barrel of production $ 5.30 4.24 4.13 ========== ========== ==========
92 93 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
CANADA ------------------------------------ YEAR ENDED DECEMBER 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 193,100 161,030 178,244 Production and operating expenses (51,194) (49,571) (44,366) Depreciation, depletion and amortization (64,514) (43,392) (91,886) Reduction of carrying value of oil and gas properties -- -- (625,514) Income tax (expense) benefit (37,736) (37,615) 204,159 ---------- ---------- ---------- Results of operations for oil and gas producing activities $ 39,656 30,452 (379,363) ========== ========== ========== Depreciation, depletion and amortization per equivalent barrel of production $ 3.56 2.41 5.64 ========== ========== ==========
INTERNATIONAL ------------------------------------ YEAR ENDED DECEMBER 31, ------------------------------------ 1999 1998 1997 ---------- ---------- ---------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 2,901 -- -- Production and operating expenses (1,500) -- -- Depreciation, depletion and amortization (62) -- -- Amortization of goodwill (5) -- -- Income tax expense (334) -- -- ---------- ---------- ---------- Results of operations for oil and gas producing activities $ 1,000 -- -- ========== ========== ========== Depreciation, depletion and amortization per equivalent barrel of production $ 0.14 -- -- ========== ========== ==========
16. 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." Quantities of Oil and Gas Reserves 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, 1999. Approximately 97%, 93% and 93%, of the respective year-end 1999, 1998 and 1997 domestic proved reserves were calculated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and, for 1999 only, Ryder-Scott Company Petroleum Consultants. The remaining percentages of domestic reserves are based on Devon's own estimates. All of the year-end 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates. All of the 93 94 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 year-end 1998 and 1997 Canadian proved reserves were calculated by the independent petroleum consultants of Paddock Lindstrom & Associates, AMH Group Ltd. and, for 1997 only, John P. Hunter & Associates, Ltd. All of the international proved reserves other than Canada as of December 31, 1999, were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants.
TOTAL ------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ----------- ----------- ----------- Proved reserves as of December 31, 1996 80,155 898,319 14,190 Revisions of estimates 42 (46,390) 1,544 Extensions and discoveries 9,387 145,508 424 Purchase of reserves 19,396 275,592 2,914 Production (11,783) (121,810) (1,891) Sale of reserves (156) (615) (3) ----------- ----------- ----------- Proved reserves as of December 31, 1997 97,041 1,150,604 17,178 Revisions of estimates (6,277) (68,895) 176 Extensions and discoveries 1,897 116,227 452 Purchase of reserves 8,683 145,629 518 Production (11,903) (133,065) (1,939) Sale of reserves (5,984) (11,606) (306) ----------- ----------- ----------- Proved reserves as of December 31, 1998 83,457 1,198,894 16,079 Revisions of estimates 3,427 (8,958) 3,065 Extensions and discoveries 1,309 136,957 2,042 Purchase of reserves 235,512 821,547 32,795 Production (15,416) (198,457) (4,022) Sale of reserves (4,372) (53,456) (142) ----------- ----------- ----------- Proved reserves as of December 31, 1999 303,917 1,896,527 49,817 =========== =========== =========== Proved developed reserves as of: December 31, 1996 72,330 810,465 12,563 December 31, 1997 88,258 984,374 16,332 December 31, 1998 73,846 1,052,647 15,081 December 31, 1999 171,249 1,751,385 47,502
94 95 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DOMESTIC ------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ----------- ----------- ----------- Proved reserves as of December 31, 1996 59,951 554,661 11,695 Revisions of estimates (1,358) (21,124) 1,531 Extensions and discoveries 7,394 94,925 301 Purchase of reserves 1,126 992 16 Production (6,055) (61,015) (1,468) Sale of reserves (156) (615) (3) ----------- ----------- ----------- Proved reserves as of December 31, 1997 60,902 567,824 12,072 Revisions of estimates (12,560) 1,507 424 Extensions and discoveries 1,242 53,708 371 Purchase of reserves 513 39,855 -- Production (5,646) (65,907) (1,373) Sale of reserves -- -- -- ----------- ----------- ----------- Proved reserves as of December 31, 1998 44,451 596,987 11,494 Revisions of estimates 6,255 32,086 3,333 Extensions and discoveries 1,090 84,259 1,594 Purchase of reserves 106,008 803,434 32,709 Production (9,791) (124,896) (3,322) Sale of reserves (2,489) (7,784) (4) ----------- ----------- ----------- Proved reserves as of December 31, 1999 145,524 1,384,086 45,804 =========== =========== =========== Proved developed reserves as of: December 31, 1996 52,672 529,407 10,328 December 31, 1997 53,059 462,082 11,289 December 31, 1998 40,631 469,064 10,577 December 31, 1999 128,167 1,246,131 43,637
95 96 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
CANADA ---------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ---------- ---------- ---------- Proved reserves as of December 31, 1996 20,204 343,658 2,495 Revisions of estimates 1,400 (25,266) 13 Extensions and discoveries 1,993 50,583 123 Purchase of reserves 18,270 274,600 2,898 Production (5,728) (60,795) (423) Sale of reserves -- -- -- ---------- ---------- ---------- Proved reserves as of December 31, 1997 36,139 582,780 5,106 Revisions of estimates 6,283 (70,402) (248) Extensions and discoveries 655 62,519 81 Purchase of reserves 8,170 105,774 518 Production (6,257) (67,158) (566) Sale of reserves (5,984) (11,606) (306) ---------- ---------- ---------- Proved reserves as of December 31, 1998 39,006 601,907 4,585 Revisions of estimates (2,828) (41,044) (268) Extensions and discoveries 219 52,698 448 Purchase of reserves 2,796 11,890 86 Production (5,178) (73,561) (700) Sale of reserves (1,883) (45,672) (138) ---------- ---------- ---------- Proved reserves as of December 31, 1999 32,132 506,218 4,013 ========== ========== ========== Proved developed reserves as of December 31, 1996 19,658 281,058 2,235 December 31, 1997 35,199 522,292 5,043 December 31, 1998 33,215 583,583 4,504 December 31, 1999 29,268 501,376 3,865
96 97 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
INTERNATIONAL ---------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ------------ ------------ ------------ Proved reserves as of December 31, 1998 -- -- -- Revisions of estimates -- -- -- Extensions and discoveries -- -- -- Purchase of reserves 126,708 6,223 -- Production (447) -- -- Sale of reserves -- -- -- ------------ ------------ ------------ Proved reserves as of December 31, 1999 126,261 6,223 -- ============ ============ ============ Proved developed reserves as of December 31, 1999 13,814 3,878 --
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:
TOTAL ---------------------------------------------- DECEMBER 31, ---------------------------------------------- 1999 1998 1997 ------------ ------------ ------------ (IN THOUSANDS) Future cash inflows $ 11,308,329 2,984,585 3,728,815 Future costs: Development (786,878) (157,577) (158,761) Production (3,808,693) (1,169,988) (1,348,459) Future income tax expense (916,198) (125,975) (399,972) ------------ ------------ ------------ Future net cash flows 5,796,560 1,531,045 1,821,623 10% discount to reflect timing of cash flows (2,657,626) (599,457) (720,947) ------------ ------------ ------------ Standardized measure of discounted future net cash flows $ 3,138,934 931,588 1,100,676 ============ ============ ============
97 98 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
DOMESTIC ------------------------------------------- DECEMBER 31, ------------------------------------------- 1999 1998 1997 ----------- ----------- ----------- ` (IN THOUSANDS) Future cash inflows $ 6,971,518 1,650,930 2,304,602 Future costs: Development (427,097) (72,215) (83,350) Production (2,449,871) (678,732) (806,130) Future income tax expense (495,599) (86,412) (269,880) ----------- ----------- ----------- Future net cash flows 3,598,951 813,571 1,145,242 10% discount to reflect timing of cash flows (1,398,612) (319,889) (481,263) ----------- ----------- ----------- Standardized measure of discounted future net cash flows $ 2,200,339 493,682 663,979 =========== =========== ===========
CANADA ------------------------------------------- DECEMBER 31, ------------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Future cash inflows $ 1,666,358 1,333,655 1,424,213 Future costs: Development (66,631) (85,362) (75,411) Production (514,825) (491,256) (542,329) Future income tax expense (204,290) (39,563) (130,092) ----------- ----------- ----------- Future net cash flows 880,612 717,474 676,381 10% discount to reflect timing of cash flows (320,722) (279,568) (239,684) ----------- ----------- ----------- Standardized measure of discounted future net cash flows $ 559,890 437,906 436,697 =========== =========== ===========
98 99 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
INTERNATIONAL ------------------------------------------ DECEMBER 31, ------------------------------------------ 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Future cash inflows $ 2,670,453 -- -- Future costs: Development (293,150) -- -- Production (843,997) -- -- Future income tax expense (216,309) -- -- ----------- ----------- ----------- Future net cash flows 1,316,997 -- -- 10% discount to reflect timing of cash flows (938,292) -- -- ----------- ----------- ----------- Standardized measure of discounted future net cash flows $ 378,705 -- -- =========== =========== ===========
F Future cash inflows are computed by applying year-end prices (averaging $21.96 per barrel of oil, adjusted for transportation and other charges, $1.87 per Mcf of gas and $15.74 per barrel of natural gas liquids at December 31, 1999) 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. 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. 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. 99 100 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 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:
YEAR ENDED DECEMBER 31, ------------------------------------------- 1999 1998 1997 ----------- ----------- ----------- (IN THOUSANDS) Beginning balance $ 931,588 1,100,676 1,454,974 Sales of oil, gas and natural gas liquids, net of production costs (525,600) (242,260) (331,980) Net changes in prices and production costs 658,640 (304,593) (890,534) Extensions, discoveries, and improved recovery, net of future development costs 115,132 64,614 75,698 Purchase of reserves, net of future development costs 2,147,781 113,655 246,173 Development costs incurred during the period which reduced future development costs 37,080 45,699 62,868 Revisions of quantity estimates 42,479 (58,314) (12,251) Sales of reserves in place (74,207) (28,365) (1,395) Accretion of discount 100,904 134,065 198,401 Net change in income taxes (417,637) 162,517 300,684 Other, primarily changes in timing 122,774 (56,106) (1,962) ----------- ----------- ----------- Ending balance $ 3,138,934 931,588 1,100,676 =========== =========== ===========
17. SEGMENT INFORMATION Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three 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 Notes 15 and 16. Following is certain financial information regarding Devon's segments for 1999, 1998 and 1997. The revenues reported are all from external customers. 100 101 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997
U.S. CANADA INTERNATIONAL TOTAL ----------- ----------- ------------- ----------- (IN THOUSANDS) AS OF DECEMBER 31, 1999: Current assets $ 321,528 69,279 26,387 417,194 Property and equipment, net of accumulated depreciation, depletion and amortization 2,373,815 467,465 314,640 3,155,920 Other assets 915,558 98 134,390 1,050,046 ----------- ----------- ----------- ----------- Total assets $ 3,610,901 536,842 475,417 4,623,160 =========== =========== =========== =========== Current liabilities 166,144 44,989 16,311 227,444 Long-term debt 1,447,780 339,341 -- 1,787,121 Deferred tax liabilities 362,414 1,733 26,718 390,865 Other liabilities 146,706 3,098 42,406 192,210 Stockholders' equity 1,487,857 147,681 389,982 2,025,520 ----------- ----------- ----------- ----------- Total liabilities and stockholders' equity $ 3,610,901 536,842 475,417 4,623,160 =========== =========== =========== =========== YEAR ENDED DECEMBER 31, 1999: REVENUES Oil sales $ 194,162 76,171 2,901 273,234 Gas sales 279,030 106,895 -- 385,925 Natural gas liquids sales 46,310 10,034 -- 56,344 Other 14,074 4,652 270 18,996 ----------- ----------- ----------- ----------- Total revenues 533,576 197,752 3,171 734,499 ----------- ----------- ----------- ----------- COSTS AND EXPENSES Lease operating expenses 115,517 49,831 1,500 166,848 Production taxes 21,692 1,363 -- 23,055 Depreciation, depletion and amortization of property and equipment 188,892 65,176 207 254,275 Amortization of goodwill 16,106 -- 5 16,111 General and administrative expenses 39,107 12,189 2,549 53,845 Interest expense 41,979 24,945 (11) 66,913 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- (13,154) -- (13,154) Distributions on preferred securities of subsidiary trust 6,884 -- -- 6,884 ----------- ----------- ----------- Total costs and expenses 430,177 140,350 4,250 574,777 ----------- ----------- ----------- ----------- Earnings (loss) before income tax expense (benefit) 103,399 57,402 (1,079) 159,722 INCOME TAX EXPENSE (BENEFIT) Current 21,748 2,908 -- 24,656 Deferred 14,019 26,654 (163) 40,510 ----------- ----------- ----------- ----------- Total income tax expense (benefit) 35,767 29,562 (163) 65,166 ----------- ----------- ----------- ----------- Net earnings (loss) $ 67,632 27,840 (916) 94,556 =========== =========== =========== =========== Capital expenditures $ 213,754 91,853 9,198 314,805 =========== =========== =========== ===========
101 102 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 17. SEGMENT INFORMATION (CONTINUED)
U.S. CANADA INTERNATIONAL TOTAL ----------- ----------- ------------- ----------- (IN THOUSANDS) AS OF DECEMBER 31, 1998: Current assets $ 57,098 53,550 -- 110,648 Property and equipment, net of accumulated depreciation, depletion and amortization 635,440 465,488 -- 1,100,928 Other assets 13,326 1,454 -- 14,780 ----------- ----------- ----------- ----------- Total assets $ 705,864 520,492 -- 1,226,356 =========== =========== =========== =========== Current liabilities 25,032 55,624 -- 80,656 Long-term debt 35,000 370,271 -- 405,271 Deferred tax liabilities (assets) 57,393 (24,174) -- 33,219 Other liabilities 28,987 5,760 -- 34,747 TCP Securities 149,500 -- -- 149,500 Stockholders' equity 409,952 113,011 -- 522,963 ----------- ----------- ----------- ----------- Total liabilities and stockholders' equity $ 705,864 520,492 -- 1,226,356 =========== =========== =========== =========== YEAR ENDED DECEMBER 31, 1998: REVENUES Oil sales $ 70,286 73,338 -- 143,624 Gas sales 126,273 83,071 -- 209,344 Natural gas liquids sales 12,071 4,621 -- 16,692 Other 4,094 13,754 -- 17,848 ----------- ----------- ----------- ----------- Total revenues 212,724 174,784 -- 387,508 ----------- ----------- ----------- ----------- COSTS AND EXPENSES Lease operating expenses 65,574 47,910 -- 113,484 Production taxes 12,255 1,661 -- 13,916 Depreciation, depletion and amortization 79,254 44,590 -- 123,844 General and administrative expenses 11,052 12,502 -- 23,554 Northstar Combination expenses 3,064 10,085 -- 13,149 Interest expense 658 21,974 -- 22,632 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- 16,104 -- 16,104 Distributions on preferred securities of subsidiary trust 9,717 -- -- 9,717 Reduction of carrying value of oil and gas properties 126,900 -- -- 126,900 ----------- ----------- ----------- ----------- Total costs and expenses 308,474 154,826 -- 463,300 ----------- ----------- ----------- ----------- Earnings (loss) before income tax expense (benefit) (95,750) 19,958 -- (75,792) INCOME TAX EXPENSE (BENEFIT) Current 5,712 1,975 -- 7,687 Deferred (34,360) 11,166 -- (23,194) ----------- ----------- ----------- ----------- Total income tax expense (benefit) (28,648) 13,141 -- (15,507) ----------- ----------- ----------- ----------- Net earnings (loss) $ (67,102) 6,817 -- (60,285) =========== =========== =========== =========== Capital expenditures $ 170,334 205,178 -- 375,512 =========== =========== =========== ===========
102 103 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 17. SEGMENT INFORMATION (CONTINUED)
U.S. CANADA INTERNATIONAL TOTAL ----------- ----------- ------------- ----------- (IN THOUSANDS) AS OF DECEMBER 31, 1997: Current assets $ 81,517 131,740 -- 213,257 Property and equipment, net of accumulated depreciation, depletion and amortization 679,677 315,606 -- 995,283 Other assets 14,940 25,506 -- 40,446 ----------- ----------- ----------- ----------- Total assets $ 776,134 472,852 -- 1,248,986 =========== =========== =========== =========== Current liabilities 29,016 107,298 -- 136,314 Long-term debt -- 305,337 -- 305,337 Deferred tax liabilities (assets) 92,042 (60,217) -- 31,825 Other liabilities 21,040 8,424 -- 29,464 TCP Securities 149,500 -- -- 149,500 Stockholders' equity 484,536 112,010 -- 596,546 ----------- ----------- ----------- ----------- Total liabilities and stockholders' equity $ 776,134 472,852 -- 1,248,986 =========== =========== =========== =========== YEAR ENDED DECEMBER 31, 1997: REVENUES Oil sales $ 115,504 92,221 -- 207,725 Gas sales 139,018 80,441 -- 219,459 Natural gas liquids sales 19,338 5,582 -- 24,920 Other 4,974 42,581 -- 47,555 ----------- ----------- ----------- ----------- Total revenues 278,834 220,825 -- 499,659 ----------- ----------- ----------- ----------- COSTS AND EXPENSES Lease operating expenses 58,112 42,785 -- 100,897 Production taxes 17,646 1,581 -- 19,227 Depreciation, depletion and amortization 75,944 93,164 -- 169,108 General and administrative expenses 10,481 13,900 -- 24,381 Interest expense 269 18,519 -- 18,788 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- 5,860 -- 5,860 Distributions on preferred securities of subsidiary trust 9,717 -- -- 9,717 Reduction of carrying value of oil and gas properties -- 625,514 -- 625,514 ----------- ----------- ----------- ----------- Total costs and expenses 172,169 801,323 -- 973,492 ----------- ----------- ----------- ----------- Earnings (loss) before income tax expense (benefit) 106,665 (580,498) -- (473,833) INCOME TAX EXPENSE (BENEFIT) Current 21,180 5,677 -- 26,857 Deferred 18,603 (219,302) -- (200,699) ----------- ----------- ----------- ----------- Total income tax expense (benefit) 39,783 (213,625) -- (173,842) ----------- ----------- ----------- ----------- Net earnings (loss) $ 66,882 (366,873) -- (299,991) =========== =========== =========== =========== Capital expenditures $ 120,689 167,302 -- 287,991 =========== =========== =========== ===========
103 104 DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1999, 1998 AND 1997 18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Following is a summary of the unaudited interim results of operations for the years ended December 31, 1999 and 1998.
1999 ----------------------------------------------------------------- FIRST SECOND THIRD FOURTH FULL QUARTER QUARTER QUARTER QUARTER YEAR -------- ------- -------- ------- ------ (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Oil, gas and natural gas liquids sales $85,393 102,093 214,241 313,776 715,503 Total revenues $87,266 104,312 219,851 323,070 734,499 Net earnings $ 5,980 16,209 24,452 47,915 94,556 Net earnings per common share: Basic $ 0.12 0.33 0.39 0.55 1.51 Diluted $ 0.12 0.33 0.38 0.52 1.46
1998 ----------------------------------------------------------------- FIRST SECOND THIRD FOURTH FULL QUARTER QUARTER QUARTER QUARTER YEAR -------- ------- -------- ------- ------ (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Oil, gas and natural gas liquids sales $ 98,308 93,507 90,469 87,376 369,660 Total revenues $ 100,437 104,775 92,870 89,426 387,508 Net earnings (loss) $ 14,225 12,173 (83,195) (3,488) (60,285) Net earnings (loss) per common share: Basic $ 0.29 0.25 (1.72) (0.07) (1.25) Diluted $ 0.29 0.25 (1.72) (0.07) (1.25)
The third quarter of 1998 includes a $126.9 million pre-tax reduction of the carrying value of U.S. oil and gas properties. The after-tax effect of this charge was $88 million, or $1.82 per share. The fourth quarter of 1998 includes $13.1 million of costs incurred in connection with the Northstar Combination. The after-tax effect of these expenses was $9.7 million, or $0.20 per share. 104 105 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000. 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 the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000. 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 the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000. 105 106 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES, AND REPORTS ON FORM 8-K (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 on Page 48 of 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 2.1 Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma) (formerly Devon Energy Corporation, an Oklahoma corporation), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999 (incorporated by reference to Exhibit 2.1 to Registrant's Form S-4, File No. 333-82903). 2.2 Amended and Restated Combination Agreement between the Registrant and Northstar Energy Corporation dated as of June 29, 1998 (incorporated by reference to Annex B to Registrant's definitive proxy statement for a special meeting of shareholders, filed November 6, 1998). 3.1 Registrant's Restated Certificate of Incorporation (incorporated by reference to Exhibit 3 to Registrant's Form 8-K filed on August 18, 1999). 3.2 Registrant's Bylaws (incorporated by reference to Exhibit 3.3 to Registrant's Registration Statement on Form S-4, File No. 333-82903 as filed on July 15, 1999). 4.1 Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Registrant's Form 8-K filed on August 18, 1999). 106 107 4.2 Rights Agreement dated as of August 17, 1999 between Registrant and BankBoston, N.A. (incorporated by reference to Exhibit 4.2 to Registrant's Form 8-K filed on August 18, 1999). 4.3 Certificate of Designations of Series A Junior Participating Preferred Stock of Registrant (incorporated by reference to Exhibit 4.3 to Registrant's Form 8-K filed on August 18, 1999). 4.4 Certificate of Designations of the 6.49% Cumulative Preferred Stock, Series A of Registrant (incorporated by reference to Exhibit 4.4 to Registrant's Form 8-K filed on August 18, 1999). 4.5 Description of Capital Stock of Registrant (incorporated by reference to Exhibit 4.9 to Registrant's Form 8-K filed on August 18, 1999). 4.6 Indenture dated as of December 15, 1992 between Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Texas Commerce Bank National Association, Trustee (incorporated by reference to Exhibit 4(o) to Pennzoil Company's Form 10-K filed on March 10, 1993 (SEC File No. 1-5591)). 4.7 Third Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.90% Exchangeable Senior Debentures due August 15, 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company's 1998 Form 10-K filed on March 23, 1999). 4.8 Fourth Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.95% Exchangeable Senior Debentures due August 15, 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company's 1998 Form 10-K filed on March 23, 1999). 107 108 4.9 Fifth Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4.7 to Registrant's Form 8-K filed on August 18, 1999). 4.10 Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4(a) to Pennzoil Company's Form 10-Q filed on July 31, 1986 (SEC File No. 1-5591). 4.11 First Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4.8 to Registrant's Form 8-K filed on August 18, 1999). 4.12 Second Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of July 3, 1996 among the Registrant and The Bank of New York, as Trustee and the First Supplemental Indenture dated as of July 3, 1996 between the Registrant and The Bank of New York, as Trustee, relating to the issuance of 6.5% Trust Convertible Preferred Junior Subordinated Debentures (incorporated by reference to Exhibit 4.6 to Registrant's Form 8-K filed on August 18, 1999). 4.13 Amending Support Agreement dated as of August 17, 1999 between Registrant and Northstar Energy Corporation (incorporated by reference to Exhibit 4.5 to Registrant's Form 8-K filed on August 18, 1999). 4.14 Support Agreement, dated December 10, 1998, between the Registrant and Northstar Energy Corporation (incorporated by reference to Exhibit 4.1 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K dated as of December 11, 1998). 4.15 Registration Rights Agreement, dated December 31, 1996, by and between Registrant and Kerr-McGee Corporation 108 109 (incorporated by reference to Exhibit 4.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on January 14, 1997). 4.16 Exchangeable Share Provisions (incorporated by reference to Exhibit 4.2 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on December 23, 1998). 4.17 Amended Exchangeable Share Provisions dated as of August 17, 1999. 9.1 Voting and Exchange Trust Agreement, dated December 10, 1998, by and between the Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company (incorporated by reference to Exhibit 9 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on December 23, 1998). 9.2 Amending Voting and Exchange Trust Agreement, dated as of August 17, 1999, by and between Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company (incorporated by reference to Exhibit 9 to Registrant's Form 8-K filed on August 18, 1999). 10.1 U.S. Credit Agreement, dated October 15, 1999 among the Registrant, as U.S. Borrower, Bank of America, N.A., as Administrative Agent, Bank of America Securities, LLC, as Lead Arranger, Bank One, Texas, N.A., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders (incorporated by reference to Exhibit 10.1 to Registrant's Form 10-Q filed on November 8, 1999). 10.2 Canadian Credit Agreement dated October 15, 1999, among Northstar Energy Corporation and Devon Energy Corporation, as Canadian Borrowers, Bank of America Canada, as Administrative Agent Bank of America Securities, LLC, as Lead Arranger, BancOne Capital Markets, Inc., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union 109 110 National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders (incorporated by reference to Exhibit 10.2 to Registrant's Form 10-Q filed on November 8, 1999). 10.3 Morrison Petroleums Ltd. U.S. $75,000,000 6.76% Senior Notes Due July 19, 2005 Note Agreement dated as of July 19, 1995 (incorporated by reference to Exhibit 10.3 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 10-K filed on March 31, 1999.) 10.4 Northstar Energy Corporation U.S. $150,000,000 6.79% Senior Notes Due 2009 Note Agreement dated as of March 2, 1998 (incorporated by reference to Exhibit 10.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 10-K filed on March 31, 1999). 10.5 Pennzoil Company 1990 Stock Option Plan (incorporated by reference to Exhibit A to Pennzoil Company's definitive proxy material filed on April 26, 1990, (SEC File No. 1-5591).* 10.6 Pennzoil Company 1990 Conditional Stock Award Program (incorporated by reference to Exhibit B to Pennzoil Company's definitive proxy material filed on April 26, 1990, SEC File No. 1-5591).* 10.7 Pennzoil Company 1992 Stock Option Plan (incorporated by reference to Exhibit A to Pennzoil Company definitive proxy material filed on April 13, 1993, SEC File No. 1-5591).* 10.8 Pennzoil Company 1993 Conditional Stock Award Program (incorporated by reference to Exhibit B to Pennzoil Company's definitive proxy material filed on April 13, 1993, SEC File No. 1-5591). * 10.9 Pennzoil Company 1997 Incentive Plan (incorporated by reference to Exhibit A to Pennzoil Company definitive proxy material filed on March 21, 1997, SEC File No. 1-5591).* 10.10 PennzEnergy Company 1998 Incentive Plan (incorporated by reference to Exhibit 4.3 to Pennzoil Company's Form S-8 filed on December 29, 1998 SEC No. 333-69845).* 110 111 10.11 Devon Energy Corporation 1988 Stock Option Plan (incorporated by reference to Exhibit 10.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Registration Statement on Form S-4 filed on July 15, 1999, SEC File No. 33-23564).* 10.12 Devon Energy Corporation 1993 Stock Option Plan (incorporated by reference to Exhibit A to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Proxy Statement for the 1993 Annual Meeting of Shareholders filed on May 6, 1993).* 10.13 Devon Energy Corporation 1997 Stock Option Plan (incorporated by reference to Exhibit A to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Proxy Statement for the 1997 Annual Meeting of Shareholders filed on April 3, 1997).* 10.14 Employment Agreement between Devon Energy Corporation (Nevada), Registrant and Duke R. Ligon, dated February 7, 1997 (incorporated by reference to Exhibit 10.12 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on July 22, 1997).* 10.15 Amendment to Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated September 30, 1999.* 10.16 Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated March 26, 1997 (incorporated by reference to Exhibit 10.13 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on July 22, 1997).* 10.17 Supplemental Benefit Agreement between Northstar Energy Corporation and John A. Hagg dated February 17, 1999 (incorporated by reference to Exhibit 10.15 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Annual Report on Form 10-K filed on March 31, 1999).* 111 112 10.18 Severance Agreement between Devon Energy Corporation (Nevada), Devon Energy Corporation, Devon Delaware Corporation and J. Larry Nichols, dated May 19, 1999 (incorporated by reference to Exhibit 10.4 to Registrant's Form 10-Q filed on November 8, 1999).* 10.19 Form of Severance Agreement between Devon Energy Corporation (Nevada), Devon Energy Corporation, Devon Delaware Corporation and J. Michael Lacey, Marian J. Moon, Duke R. Ligon, Darryl G. Smette, H. Allen Turner and William T. Vaughn, dated May 19, 1999 (incorporated by reference to Exhibit 10.3 to Registrant's Form 10-Q filed on November 8, 1999).* 10.20 Director's Restricted Stock Award Agreement between Devon Delaware Corporation (predecessor to Registrant) and James L. Pate, dated August 17, 1999.* 10.21 Consulting Agreement between Registrant (as successor by merger to PennzEnergy) and Brent Scowcroft dated May 17, 1999.* 10.22 Sale and Purchase Agreement relating to Registrant's San Juan Basin gas properties (incorporated by reference to Exhibit 10.15 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on November 9, 1995). 10.23 Second Restatement of and Amendment to Sale and Purchase Agreement relating to Registrant's San Juan Basin gas properties (incorporated by reference to Exhibit 10.16 to Devon Energy Corporation (Oklahoma)'s (predecessor to Registrant) Form 10-Q filed on November 9, 1995). 12 Computation of ratio of earnings to fixed charges 21 Subsidiaries of Registrant 23.1 Consent of LaRoche Petroleum Consultants, Ltd. 23.2 Consent of AMH Group, Ltd. 23.3 Consent of Paddock Lindstrom & Associates Ltd. 23.4 Consent of KPMG LLP 23.5 Consent of Ryder-Scott Company Petroleum Consultants 23.6 Consent of Deloitte & Touche LLP 27 Financial Data Schedule (filed electronically only) * Compensatory plans or arrangements. Reports on Form 8-K - A Current Report on Form 8-K dated January 26, 2000, was filed by the Registrant regarding year-end 1999 oil and gas reserves and 2000 forward-looking information. 112 113 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 March 28, 2000 By /s/ J. Larry Nichols --------------------------- J. Larry Nichols, President 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. March 28, 2000 By /s/ James L. Pate ------------------------ James L. Pate Chairman of the Board and Director March 28, 2000 By /s/ J. Larry Nichols --------------------------- J. Larry Nichols President, Chief Executive Officer and Director March 28, 2000 By /s/ William T. Vaughn ---------------------------- William T. Vaughn Senior Vice President - Finance March 28, 2000 By /s/ Danny J. Heatly -------------------------- Danny J. Heatly Vice President - Accounting 113 114 March 28, 2000 By /s/ Thomas F. Ferguson ----------------------------- Thomas F. Ferguson, Director March 28, 2000 By /s/ David M. Gavrin -------------------------- David M. Gavrin, Director March 28, 2000 By /s/ Michael E. Gellert ----------------------------- Michael E. Gellert, Director March 28, 2000 By /s/ Moulton Goodrum, Jr. ------------------------------- Moulton Goodrum, Jr., Director March 28, 2000 By /s/ John A. Hagg ----------------------- John A. Hagg, Director March 28, 2000 By /s/ Henry R. Hamman -------------------------- Henry R. Hamman, Director March 28, 2000 By /s/ William J. Johnson ----------------------------- William J. Johnson, Director March 28, 2000 By /s/ Michael M. Kanovsky ------------------------------ Michael M. Kanovsky, Director March 28, 2000 By /s/ Robert Mosbacher, Jr. -------------------------------- Robert Mosbacher, Jr., Director March 28, 2000 By /s/ H. R. Sanders, Jr. ----------------------------- H. R. Sanders, Jr., Director March 28, 2000 By /s/ Brent Scowcroft Brent Scowcroft, Director March 28, 2000 By /s/ Robert B. Weaver --------------------------- Robert B. Weaver, Director 114 115 INDEX TO EXHIBITS
Exhibit Page - - - - - - - - ------- ---- 2.1 Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma) (formerly Devon Energy Corporation, an Oklahoma corporation), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999.......... * 2.2 Amended and Restated Combination Agreement between the Registrant and Northstar Energy Corporation dated as of June 29, 1998.............* 3.1 Registrant's Restated Certificate of Incorporation.....................* 3.2 Registrant's Bylaws....................................................* 4.1 Form of Common Stock Certificate.......................................* 4.2 Rights Agreement dated as of August 17, 1999 between Registrant and BankBoston, N.A....................................................* 4.3 Certificate of Designations of Series A Junior Participating Preferred Stock of Registrant..........................................* 4.4 Certificate of Designations of the 6.49% Cumulative Preferred Stock, Series A of Registrant..........................................*
115 116 4.5 Description of Capital Stock of Registrant.............................* 4.6 Indenture dated as of December 15, 1992 between Registrant (as successor by merger to PennzEnergy, successor to Pennzoil Company) and Texas Commerce Bank National Association, Trustee.........* 4.7 Third Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.90% Exchangeable Senior Debentures due August 15, 2008.....................* 4.8 Fourth Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.95% Exchangeable Senior Debentures due August 15, 2008.....................* 4.9 Fifth Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association...................................................* 4.10 Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Chase Bank of Texas, National Association............................................................* 4.11 First Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association...................................................* 4.12 Second Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of July 3, 1996 among the Registrant and The Bank of New York, as Trustee and the First Supplemental Indenture dated as of July 3, 1996 between the Registrant and The Bank of New York, as Trustee, relating to the issuance of 6.5% Trust Convertible Preferred Junior Subordinated Debentures.............................................................*
116 117 4.13 Amending Support Agreement dated as of August 17, 1999 between Registrant and Northstar Energy Corporation............................* 4.14 Support Agreement, dated December 10, 1998, between the Registrant and Northstar Energy Corporation.......................................* 4.15 Registration Rights Agreement, dated December 31, 1996, by and between Registrant and Kerr-McGee Corporation..........................* 4.16 Exchangeable Share Provisions..........................................* 4.17 Amended Exchangeable Share Provisions dated as of August 17, 1999......................................................121 9.1 Voting and Exchange Trust Agreement, dated December 10, 1998, by and between Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company...................................................* 9.2 Amending Voting and Exchange Trust Agreement, dated as of August 17, 1999, by and between Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company..........................................* 10.1 U.S. Credit Agreement, dated October 15, 1999 among the Registrant, as U.S. Borrower, Bank of America, N.A., as Administrative Agent, Bank of America Securities, LLC, as Lead Arranger, Bank One, Texas, N.A., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders.............................................................* 10.2 Canadian Credit Agreement dated October 15, 1999, among Northstar Energy Corporation and Devon Energy Corporation, as Canadian Borrowers, Bank of America Canada, as Administrative Agent, Bank of America Securities, LLC, as Lead Arranger, BancOne Capital Markets, Inc., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders.............................................................* 10.3 Morrison Petroleums Ltd. U.S. $75,000,000 6.76% Senior Notes Due July 19, 2005 Note Agreement dated as of July 19, 1995.................*
117 118 10.4 Northstar Energy Corporation U.S. $150,000,000 6.79% Senior Notes Due 2009 Note Agreement dated as of March 2, 1998......................* 10.5 Pennzoil Company 1990 Stock Option Plan................................* 10.6 Pennzoil Company 1990 Conditional Stock Award Program..................* 10.7 Pennzoil Company 1992 Stock Option Plan................................* 10.8 Pennzoil Company 1993 Conditional Stock Award Program..................* 10.9 Pennzoil Company 1997 Incentive Plan...................................* 10.10 PennzEnergy Company 1998 Incentive Plan................................* 10.11 Devon Energy Corporation 1988 Stock Option Plan........................* 10.12 Devon Energy Corporation 1993 Stock Option Plan........................* 10.13 Devon Energy Corporation 1997 Stock Option Plan........................* 10.14 Employment Agreement between Devon Energy Corporation (Nevada), Registrant and Duke R. Ligon, dated February 7, 1997.................. * 10.15 Amendment to Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated September 30, 1999...................................................122 10.16 Supplemental Retirement Income Agreement among Devon Energy Corporation (Nevada), Registrant and John W. Nichols, dated March 26, 1997.........................................................* 10.17 Supplemental Benefit Agreement between Northstar Energy Corporation and John A. Hagg dated February 17, 1999...................* 10.18 Severance Agreement between Devon Energy Corporation (Nevada), Devon Energy Corporation, Devon Delaware Corporation and J. Larry Nichols, dated May 19, 1999............................................*
118 119 10.19 Form of Severance Agreement between Devon Energy Corporation (Nevada), Devon Energy Corporation, Devon Delaware Corporation and J. Michael Lacey, Marian J. Moon, Duke R. Ligon, Darryl G. Smette, H. Allen Turner and William T. Vaughn, dated May 19, 1999..............* 10.20 Director's Restricted Stock Award Agreement between Devon Delaware Corporation (predecessor to Registrant) and James L. Pate, dated August 17, 1999......................................................123 10.21 Consulting Agreement between Registrant (as successor to merger to PennzEnergy) and Brent Scowcroft dated May 17, 1999..................129 10.22 Sale and Purchase Agreement relating to Registrant's San Juan Basin gas properties...................................................* 10.23 Second Restatement of and Amendment to Sale and Purchase Agreement relating to Registrant's San Juan Basin gas properties.................* 12 Computation of ratio of earnings to fixed charges....................131 21 Subsidiaries of Registrant...........................................132 23.1 Consent of LaRoche Petroleum Consultants, Ltd........................134 23.2 Consent of AMH Group, Ltd............................................135 23.3 Consent of Paddock Lindstrom & Associates Ltd........................136
119 120 23.4 Consent of KPMG LLP..................................................137 23.5 Consent of Ryder-Scott Company Petroleum Consultants.................138 23.6 Consent of Deloitte & Touche LLP.....................................139 27 Financial Data Schedule (filed electronically only)
*Incorporated by reference. 120 EX-4.17 2 AMENDED EXCHANGABLE SHARE PROVISIONS - 8/17/99 1 EXHIBIT 4.17 AMENDED EXCHANGEABLE SHARE PROVISIONS DATED AS OF AUGUST 17, 1999 SCHEDULE OF OTHER PROVISIONS The board of directors of the Corporation may, between annual general meetings, appoint one or more additional directors of the Corporation to serve until the next annual general meeting, but the number of additional directors shall not at any time exceed one third (1/3) of the number of directors who held office at the expiration of the last annual general meeting of the Corporation. The Plan of Arrangement made effective December 10, 1998 under Section 186 of the Business Corporations Act (Alberta) be and the same is hereby amended in accordance with Section 167(1)(m) of the Business Corporations Act (Alberta) by deleting the definition of "Devon" in Section 1.1 thereof and replacing it with the following: "Devon" has the meaning provided in the Exchangeable Share Provisions 121 EX-10.15 3 AMENDMENT TO SUPPLEMENTAL RETIREMENT INCOME 1 EXHIBIT 10.15 AMENDMENT TO SUPPLEMENTAL RETIREMENT INCOME AGREEMENT THIS AMENDMENT TO SUPPLEMENTAL RETIREMENT INCOME AGREEMENT ("Amendment") is entered into as of the 30th day of September, 1999 by and between Devon Energy Corporation, a Delaware corporation (the "Corporation") and John W. Nichols (the "Executive"). WITNESSETH: WHEREAS, the Corporation and the Executive have previously entered into that certain Supplemental Retirement Income Agreement dated March 26, 1997 (the "Agreement"), which provided that the Corporation would provide to the Executive a "supplemental retirement income" pursuant to the terms of the Agreement; and WHEREAS, the parties desire to amend the Agreement to increase the amount of the supplemental retirement income provided under the Agreement. NOW, THEREFORE, for good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree that Section 1 of the Agreement shall be amended to add the following sentence: "Provided, however, effective October 1, 1999, the annual Supplemental Retirement Income shall be increased from $180,000 to $200,000, and the equal monthly installments of Supplemental Retirement Income will be increased from $15,000 to $16,666.66." IN WITNESS WHEREOF, the parties have executed this Amendment as of the day and year first above written. "Corporation" DEVON ENERGY CORPORATION, a Delaware corporation By /s/ J. Larry Nichols ----------------------------------- J. Larry Nichols, President and Chief Executive Officer "Executive" /s/ John W. Nichols ----------------------------------- John W. Nichols 122 EX-10.20 4 DIRECTOR'S RESTRICTED STOCK AWARD AGREEMENT 1 EXHIBIT 10.20 DEVON DELAWARE CORPORATION DIRECTOR'S RESTRICTED STOCK AWARD AGREEMENT THIS AGREEMENT ("Agreement") is made as of the 17th day of August, 1999, by and between Devon Delaware Corporation, a Delaware corporation (the "Company"), and James L. Pate (the "Grantee"). The Company and the Grantee therefore agree as follows: 1. GRANT OF RESTRICTED STOCK. Effective as of the Effective Time of the merger of PennzEnergy Company into the Company, as defined in that certain Amended and Restated Agreement and Plan of Merger by and among Devon Energy Corporation, Devon Delaware Corporation, Devon Oklahoma Corporation and PennzEnergy Company, dated as of May 19, 1999 (the"Date of Grant"), the Company has awarded to the Grantee a total of 15,000 shares of Common Stock, subject to the conditions and restrictions set forth below (the "Restricted Stock"). 2. RESTRICTIONS. The shares of Restricted Stock granted hereunder to the Grantee may not be sold, assigned, transferred, pledged or otherwise encumbered from the Date of Grant until the date that the Grantee obtains a vested right to the shares (and the restrictions thereon terminate) in accordance with the provisions of this Section 2 or as otherwise provided in Section 6 below. (The period of time between the Date of Grant and the date that the Grantee obtains a vested right to shares of Restricted Stock shall be referred to herein as the "Restricted Period" as to those shares of stock.) In the event that any day on which the Grantee would otherwise obtain a vested right to additional shares of Restricted Stock is a Saturday, Sunday or holiday, the Grantee shall instead obtain that vested right on the first business day immediately following such date. The Grantee shall have a vested right to the number of shares of Restricted Stock indicated below as of the dates set forth below, provided that the Grantee has not resigned as a Director of the Company since the Date of Grant:
Number of Date Shares First Vested ---------- ------------------- May 1, 2000 5,000 May 1, 2001 5,000 May 1, 2002 5,000
All of the foregoing provisions of this Section 2 are subject to the provisions of Section 6 below, addressing an event that may result in forfeiture of the Grantee's interest in all or part of the Restricted Shares. 123 2 3. NO CODE SECTION 83(b) ELECTION. The Grantee shall not make an election, under Code Section 83(b), to include an amount in income in respect of the Restricted Stock. 4. SALE OF RESTRICTED STOCK. The Grantee agrees that the Grantee shall not sell, transfer or dispose of the Restricted Stock and that the Company shall not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such sale, transfer, disposition or delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement. 5. ESCROW OF SHARES. Shares of Restricted Stock shall be registered in the name of the Grantee and deposited with the Secretary of the Company, together with a stock power endorsed by the Grantee in blank. Any certificate shall bear a legend as provided by the Company, conspicuously referring to the terms, conditions and restrictions described in this Agreement. Upon termination of the Restricted Period with respect to shares of Restricted Stock, a certificate representing such shares shall be delivered upon written request to the Grantee as promptly as is reasonably practicable following such termination. 6. FORFEITURE. If the Grantee's service as Chairman of the Board of Directors of the Company shall terminate for any reason other than voluntary resignation (excluding a resignation at the request of the Board of Directors) prior to all shares of Restricted Stock having become vested pursuant to the provisions of Section 2 hereof, all such shares of Restricted Stock shall immediately be fully vested. If the Grantee shall resign voluntarily from the Board of Directors (excluding a resignation at the request of the Board of Directors) prior to vesting in any portion of the shares of Restricted Stock, the Grantee shall forfeit all right to those unvested shares of Restricted Stock unless otherwise determined by the Board. 7. BENEFICIARY DESIGNATIONS. The Grantee shall file with the Secretary of the Company on the form appended to this Agreement as Exhibit A or such other form as may be prescribed by the Company, a designation of one or more beneficiaries (each, a "Beneficiary") to whom shares otherwise due to the Grantee shall be distributed in the event of the death of the Grantee while serving as a Director of the Company. The Grantee shall have the right to change the Beneficiary or Beneficiaries from time to time; provided, however, that any change shall not become effective until received in writing by the Secretary of the Company. If any designated Beneficiary survives the Grantee but dies before receiving all of the Grantee's benefits hereunder, any remaining benefits due the Grantee shall be distributed to the deceased Beneficiary's estate. If there is no effective Beneficiary designation on file with the Secretary of the Company at the time of the Grantee's death, or if the designated Beneficiary or Beneficiaries have all predeceased such Grantee, the payment of any remaining benefits shall be made to the Grantee's estate. 124 3 8. NONALIENATION OF BENEFITS. Except as contemplated by Section 7 above, and other than pursuant to a qualified domestic relations order, no right or benefit under this Agreement shall be subject to transfer, anticipation, alienation, sale, assignment, pledge, encumbrance or charge, whether voluntary, involuntary or by operation of law, and any attempt to transfer, anticipate, alienate, sell, assign, pledge, encumber or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to any debts, contracts, liabilities or torts of the person entitled to such benefits. If the Grantee or the Grantee's Beneficiary hereunder shall become bankrupt or attempt to transfer, anticipate, alienate, assign, sell, pledge, encumber or charge any right or benefit hereunder, other than as contemplated by Section 7 above or other than pursuant to a qualified domestic relations order, or if any creditor shall attempt to subject the same to a writ of garnishment, attachment, execution, sequestration or any other form of process or involuntary lien or seizure, then such right or benefit shall cease and terminate. 9. PREREQUISITES TO BENEFITS. Neither the Grantee nor any person claiming through the Grantee shall have any right or interest in the Restricted Stock awarded hereunder, unless and until all the terms, conditions and provisions of this Agreement which affect the Grantee or such other person shall have been complied with as specified herein. 10. RIGHTS AS A STOCKHOLDER. Subject to the limitations and restrictions contained herein, the Grantee (or Beneficiary) shall have all rights as a stockholder with respect to the shares of the Restricted Stock once such shares have been registered in the Grantee's name or issued for the benefit of the Grantee hereunder. 11. ADJUSTMENTS. Appropriate adjustments shall be made to the Restricted Stock upon the occurrence of (i) a reclassification, subdivision, combination or dividend of the Company's Common Stock or (ii) a consolidation or merger with or into, or lease transfer or sale of substantially all the Company's assets to another entity. 12. NOTICE. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be: (a) delivered personally to the following address: Devon Delaware Corporation Corporate Secretary 20 North Broadway, Suite 1500 Oklahoma City, Oklahoma or 125 4 (b) sent by first class mail, postage prepaid and addressed as follows: Devon Delaware Corporation Attention: Corporate Secretary 20 North Broadway, Suite 1500 Oklahoma City, OK 73102-8260 Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally or shall be sent by first class mail, postage prepaid, to the Grantee's address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address. 13. AMENDMENT. This Agreement may be amended, provided, however, that an amendment shall not adversely affect the rights of the Grantee with respect to the Award evidenced hereby without the Grantee's written consent. 14. GRANTEE SERVICE. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the service of the Company as a Director. 15. SUCCESSORS AND ASSIGNS. This Agreement shall bind and enure to the benefit of and be enforceable by the Grantee, the Company and their respective permitted successors and assigns (including personal representatives, heirs and legatees), except that the Grantee may not assign any rights or obligations under this Agreement except to the extent and in a manner expressly provided herein. 16. GOVERNING LAW. This Agreement shall in all respects be governed by, and construed and enforced in accordance with, the laws of the State of Delaware to the extent not preempted by federal law. 17. CONSTRUCTION. References in this Agreement to "this Agreement" and the words "herein," "hereof," "hereunder" and similar terms include all Exhibits appended hereto. The headings of the Sections of this Agreement have been included for convenience of reference only and are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof. 18. DUPLICATE ORIGINALS. The Company and the Grantee may sign any number of copies of this Agreement. Each signed copy shall be an original, but all of them together represent the same agreement. 19. ENTIRE AGREEMENT. The Grantee and the Company hereby declare and represent that no promise or agreement not herein expressed has been made and that this Agreement contains the entire agreement between the parties hereto with respect to the 126 5 Restricted Stock granted herein and replaces and makes null and void any prior agreements, oral or written, between the Grantee and the Company regarding the Restricted Stock award. 20. GRANTEE ACCEPTANCE. The Grantee shall signify acceptance of the terms and conditions of this Agreement by signing in the space provided at the end hereof and returning an executed copy to the Company. DEVON DELAWARE CORPORATION By: /s/ J. Larry Nichols ------------------------------------------ Name: J. Larry Nichols ------------------------------------ Title: President & Chief Executive Officer ------------------------------------ ACCEPTED: /s/ James L. Pate ---------------------------------------------- Grantee: James L. Pate 127 6 Exhibit A to Director's Restricted Stock Award Agreement, dated as of August ____, 1999 DEVON DELAWARE CORPORATION DESIGNATION OF BENEFICIARY I, ___________________________________ (the "Grantee"), hereby declare that upon my death _____________________________________ (the "Beneficiary") of Name ______________________________________________________________________________, Street Address City State Zip Code who is my ___________________________________________, shall be entitled to the Relationship to the Grantee Restricted Stock and all other rights accorded the Grantee by the above-referenced grant agreement (the "Agreement"). It is understood that this Designation of Beneficiary is made pursuant to the Agreement and is subject to the conditions stated therein, including the Beneficiary's survival of the Grantee's death. If any such condition is not satisfied, such rights shall devolve according to the Grantee's will or the laws of descent and distribution. It is further understood that all prior designations of beneficiary under the Agreement are hereby revoked and that this Designation of Beneficiary may only be revoked in writing, signed by the Grantee and filed with the Company prior to the Grantee's death. - - - - - - - - ---------------------------------- ---------------------------------- Date Grantee 128 EX-10.21 5 CONSULTING AGREEMENT - GENERAL BRENT SCOWCROFT 1 EXHIBIT 10.21 CONSULTING AGREEMENT The following represents the agreement between PennzEnergy Company ("PennzEnergy") and Brent Scowcroft ("Consultant") regarding consulting services. 1. Consultant will provide consulting services as requested by PennzEnergy during the period of June 1, 1999 through May 31, 2002. These consulting services will primarily relate to PennzEnergy's international projects and investments. 2. In exchange for these services, PennzEnergy will pay a retainer in the total amount of $300,000, payable in twelve (12) equal quarterly installments of $25,000, due and payable on the first day of the months of June, September, December and March, with the initial installment payable on June 1, 1999 and the last installment payable on March 1, 2002. 3. In addition, PennzEnergy will either provide transportation and lodging or reimburse Consultant for necessary travel expenses incurred in connection with rendering consulting services pursuant to this agreement. 4. While providing the consulting services contemplated by this agreement, Consultant will be acting as an independent contractor, and not as an employee of PennzEnergy under the meaning of any federal, state or local law. 5. Consultant will be responsible for all taxes and other payments due any federal, state or local government agency with respect to the quarterly retainer payments paid to Consultant by PennzEnergy. PennzEnergy will not withhold taxes or other amounts from the quarterly retainer payments and will not provide any worker's compensation, insurance or other benefits pursuant to this consulting agreement. 129 2 6. Either party may terminate this agreement at any time upon written notice; however, Consultant will be entitled to reimbursement for travel expense incurred in connection with consulting services performed prior to receipt of the written notice and the retainer will not be subject to refund to the extent one or more quarterly installments have been paid prior to termination. In the event of termination by PennzEnergy, any quarterly installment(s) not previously paid will become due and payable within 30 days following notice of termination. Agreed to this 17th day of May, 1999. /s/ James L. Pate /s/ Brent Scowcroft - - - - - - - - ------------------------------------ ------------------- By: James L. Pate Brent Scowcroft Title: Chairman of the Board 900 Seventeenth St., N.W. Suite 500 Washington, DC 20006 130 EX-12 6 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 1 EXHIBIT 12 DEVON ENERGY CORPORATION COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
YEAR DECEMBER 31, ----------------------------------- 1999 1998 1997 --------- --------- --------- (IN THOUSANDS, EXCEPT RATIOS) Earnings (loss) before income taxes $ 159,722 (75,792) (473,833) Add: Interest expense 66,913 22,632 18,788 Distributions on preferred securities of subsidiary 6,884 9,717 9,717 Amortization of costs incurred in connection with the offering of the preferred securities of subsidiary trust 148 240 269 Amortization of premium on debentures (1,328) -- -- Estimated interest factor of operating lease payments 2,069 683 505 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860 Dividends on preferred stock 5,889 -- -- --------- --------- --------- Earnings (loss) as adjusted (A) $ 227,143 (26,416) (438,694) ========= ========= ========= Fixed charges: Interest costs incurred 66,913 22,632 18,788 Distributions on preferred securities of subsidiary trust 6,884 9,717 9,717 Amortization of costs incurred in connection with the offering of the preferred securities of subsidiary trust 148 240 269 Amortization of premium on debentures (1,328) -- -- Estimated interest factor of operating lease payments 2,069 683 505 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (13,154) 16,104 5,860 Dividends on preferred stock 5,889 -- -- --------- --------- --------- Total fixed charges (B) $ 67,421 49,376 35,139 ========= ========= ========= Ratio of earnings to fixed charges (A)/(B) 3.37 N/A N/A ========= Insufficiency of earnings to cover fixed charges N/A 75,792 473,833 ========= =========
131 EX-21 7 SUBSIDIARIES OF THE REGISTRANT 1 EXHIBIT 21 DEVON ENERGY CORPORATION SUBSIDIARIES 1. 661151 ALBERTA LTD., ALBERTA 2. 410760 ALBERTA LTD., ALBERTA 3. 659502 ALBERTA INC., ALBERTA 4. 728098 ALBERTA LTD., ALBERTA 5. 172173 CANADA, INC. 6. AMERICAN SULPHUR EXPORT CORPORATION 7. AMSULEX, INC. 8. AZERBAIJAN INTERNATIONAL OPERATING COMPANY 9. BONITO PIPE LINE COMPANY 10. CACHUMA GAS PROCESSING COMPANY 11. CANOA RANCH CORPORATION 12. CANYON REEF CARRIERS, INC. 13. CAPITAN OIL PIPELINE COMPANY 14. CASPIAN INTERNATIONAL PETROLEUM COMPANY 15. CATCLAW PIPELINE, INC. 16. DBC, INC. 17. DAVID LIMITED PARTNERSHIP, ALBERTA 18. DEVON ACQUISITION CORPORATION 19. DEVON ENERGY CANADA LTD., ALBERTA 20. DEVON ENERGY CANADA CORPORATION, ALBERTA 21. DEVON ENERGY CANADA HOLDING CORPORATION, ALBERTA 22. DEVON ENERGY CORPORATION (DELAWARE) 23. DEVON ENERGY CORPORATION (NEVADA) 24. DEVON ENERGY CORPORATION (OKLAHOMA) 25. DEVON ENERGY MANAGEMENT COMPANY, L. L. C. 26. DEVON ENERGY PRODUCTION COMPANY, L. P. 27. DEVON FINANCING TRUST 28. DEVON OIL & GAS COMPANY 29. DEVON PRODUCTION CORPORATION 30. FOOTHILLS PARTNERSHIP, ALBERTA 31. MORRISON NUCLEAR LTD., DELAWARE 32. MORRISON PETROLEUMS, LTD. 33. MOUNTAIN ENERGY INC., ALBERTA 34. NORTHSTAR ENERGY CORPORATION, ALBERTA 35. NORTHSTAR ENERGY PARTNERSHIP, ALBERTA 36. NUECES INTRASTATE PIPE LINE COMPANY 37. PENNZENERGY BRAZIL, LTDA. 38. PENNZENERGY COMPANY 39. PENNZENERGY EXPLORATION AND PRODUCTION, L. L. C. 40. PENNZENERGY INSURANCE COMPANY LIMITED (BERMUDA) 41. PENNZENERGY RECEIVABLES COMPANY 42. PENNZENERGY (U.K.) COMPANY 43. PENNZOIL ASIATIC, INC. 44. PENNZOIL BENI SUEF, INC. 45. PENNZOIL CASPIAN CORPORATION 46. PENNZOIL CASPIAN DEVELOPMENT CORPORATION 47. PENNZOIL EGYPT, INC. 48. PENNZOIL ENERGY MARKETING COMPANY 49. PENNZOIL EXPLORATION AUSTRALIA, INC. 50. PENNZOIL EXPLORATION BRAZIL, INC.
132 2 51. PENNZOIL GAS MARKETING COMPANY 52. PENNZOIL INTERNATIONAL COMPANY 53. PENNZOIL INTRASTATE PIPELINE COMPANY 54. PENNZOIL OFFSHORE PIPELINE COMPANY 55. PENNZOIL PETROLEUM PIPELINE COMPANY 56. PENNZOIL PETROLEUMS, LTD. 57. PENNZOIL QATAR, INC. 58. PENNZOIL QATAR PRODUCTION, INC. 59. PENNZOIL RESOURCES CANADA LTD. 60. PENNZOIL RED SEA, INC. 61. PENNZOIL SINAI, INC. 62. PENNZOIL SUEZ, INC. 63. PENNZOIL VENEZUELA CORPORATION, S. A. 64. PEPCO PARTNERS, L. P. 65. RICHLAND DEVELOPMENT CORPORATION 66. RICHLAND TRANSITION COMPANY 67. SAGE CREEK, INC. 68. SISQUOC GAS PIPELINE COMPANY 69. THUNDER CREEK, INC. 70. TIBURON TRANSPORT COMPANY 71. VERMEJO MINERALS CORPORATION 72. VERMEJO PARK CORPORATION
133 EX-23.1 8 CONSENT OF LAROCHE PETROLEUM CONSULTANTS 1 EXHIBIT 23.1 ENGINEER'S CONSENT We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1999, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation. LAROCHE PETROLEUM CONSULTANTS, LTD. By: /s/ William M. Kazmann ---------------------- Partner March 28, 2000 134 EX-23.2 9 CONSENT OF AMH GROUP 1 EXHIBIT 23.2 ENGINEER'S CONSENT We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1998, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation. AMH GROUP LTD. /s/ Allan K. Ashton, P.Eng. ---------------------------- President March 28, 2000 135 EX-23.3 10 CONSENT OF PADDOCK LINDSTROM & ASSOCIATES LTD 1 EXHIBIT 23.3 ENGINEER'S CONSENT We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1999, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation. PADDOCK LINDSTROM & ASSOCIATES LTD. /s/ D.L. Paddock, P. Eng. ------------------------- D.L. Paddock, P. Eng. Vice-President March 28, 2000 136 EX-23.4 11 CONSENT OF KPMG LLP 1 EXHIBIT 23.4 INDEPENDENT AUDITORS' CONSENT The Board of Directors Devon Energy Corporation: We consent to incorporation by reference in the Registration Statements (No. 333-32214 and 333-85553) on Form S-8 and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation of our report dated February 9, 2000, relating to the consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 1999, 1998 and 1997 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended, which report appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation. KPMG LLP Oklahoma City, Oklahoma March 27, 2000 137 EX-23.5 12 CONSENT OF RYDER-SCOTT COMPANY 1 EXHIBIT 23.5 CONSENT OF RYDER SCOTT COMPANY, L.P. We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1999, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation. /s/ RYDER SCOTT COMPANY, L.P. Houston, Texas March 28, 2000 138 EX-23.6 13 CONSENT OF DELOITTE & TOUCHE LLP 1 EXHIBIT 23.6 INDEPENDENT AUDITORS' CONSENT We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation and our report dated January 20, 1999 to the shareholders of Northstar Energy Corporation, relating to the consolidated balance sheets of Northstar Energy Corporation and subsidiaries as at December 31, 1998 and 1997 and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity, and cash flows for each of the years then ended, which report appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation. (SIGNED) DELOITTE & TOUCHE LLP ----------------------------------- Deloitte & Touche LLP Chartered Accountants Calgary, Alberta Canada March 28, 2000 139 EX-27 14 FINANCIAL DATA SCHEDULE
5 YEAR YEAR DEC-31-1999 DEC-31-1998 DEC-31-1999 DEC-31-1998 167,167 19,154 0 0 209,405 83,858 0 0 13,441 2,750 417,194 110,648 4,974,810 2,610,511 1,818,890 1,509,583 4,623,160 1,226,356 227,444 80,656 1,787,121 405,271 0 0 1,500 0 8,608 4,842 2,015,412 518,121 4,623,160 1,226,356 715,503 369,660 734,499 387,508 0 0 0 0 189,903 127,400 0 0 66,913 22,632 159,722 (75,792) 65,166 (15,507) 94,556 (60,285) 0 0 0 0 0 0 94,556 (60,285) 1.51 (1.25) 1.46 (1.25)
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