10-K405/A 1 d92981a1e10-k405a.txt AMENDMENT NO. 1 TO FORM 10-K UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K/A (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, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 000-30176 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 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 13, 2001, was $7,974,236,970. At such date 126,320,151 shares of common stock and 2,817,992 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 2001 annual meeting of stockholders - Part III 1 PART I ITEM 1. BUSINESS The "International Regulations" section under Item 1 has been replaced in its entirety with the following: INTERNATIONAL REGULATIONS The oil and gas industry is subject to various types of regulation throughout the world. Legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, government 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. The following are significant areas of regulation. EXPLORATION AND PRODUCTION. Devon's oil and gas concessions and permits are granted by host governments and administered by various foreign government agencies. Such foreign governments require compliance with detailed regulations and orders which regulate, among other matters, drilling and operations on areas covered by concessions and permits and calculation and disbursement of royalty payments, taxes and minimum investments to the government. 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 regulations which may limit the number of wells or the locations at which Devon can drill. ENVIRONMENTAL REGULATIONS. Various government 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. In general, this consists of preparing Environmental Impact Assessments in order to receive required environmental permits to conduct drilling or construction activities. Such regulations also typically include requirements to develop emergency response plans, waste management plans, and spill contingency plans. In some countries, the application of worldwide standards, such as ISO 14000 governing 2 Environmental Management Systems, are required to be implemented for international oil and gas operations. Brazil has stringent environmental laws. The basic federal law governing the environment is Law No. 9.605 of February 12, 1998, which set up areas of conservation that receive federal protection. The governmental environmental agency is IBAMA, which has significant enforcement powers. Environmental Impact Studies are required to determine the impact of activities on the environment and provide ways to avoid or diminish negative effects of the project on the environment. CONAMA Resolution 23 of December 7, 1994 established licensing criteria for activities related to drilling and production. Prior to commencement of exploration activities, IBAMA or a state environmental agency inspects the equipment to be used and must grant a license; the inspection and grant of the license may cause delays in start-up of operations. In addition to federal regulations, state and local agencies may have additional jurisdiction. Damage to the environment results in strict liability to the holder of the Concession. Sanctions for violations can be civil, criminal and administrative in nature. GOVERNMENT TAKES AND TAXATION Foreign governments have been evaluating in recent years in and, in some cases, promulgating new rules and regulations regarding royalty payment obligations and taxes. In Brazil there are numerous taxes imposed by federal, state and municipal governments on services and equipment, which require extensive record keeping and withholdings. Among the most significant are the following: Law No. 9.779 of 1999 extended the tax for income legal entities earn with the rendering of services, technical assistance and administrative services to 25%. There is a Value Added Sales Tax (ICMS) ranging between 7% and 25% and a municipal service tax (ISS), typically paid in the place of performance, of about 5%. Excise tax (IPI) is paid on all goods manufactured or imported into Brazil that average about 10% (see exception for imports of equipment for petroleum activities above). There are "social contribution" taxes for funding Brazil's extensive social welfare programs. COFINS, a social contribution tax charged on gross receipts, including financial and currency transactions and investments is 3%, and PIS, to fund the unemployment insurance program, is financed by the employer at 0.65% of its gross monthly receipts. Additionally, there is a severance fund contribution (FGTS). A banking tax ("CPMF") on the debit of funds from an account is charges at 0.30%. In Argentina Competitiveness Law No. 25,413 amended by Law 25,453 created a new tax applicable on bank credits and debits. The tax is applicable on (1) credits and debits on current accounts in financial entities subject to the Financial Entities Law; (2) the operations carried out by financial entities subject to the Financial Entities Law where the person/entity ordering the financial operation or the beneficiaries do not use the current accounts mentioned above, and (3) the movement or handing over of funds (whether owned or belonging to third parties), by any person or entity. The General Tax Rate (subject to certain tax credits) is 0.6% in the case of debits and credits. In the cases described in points 2 and 3 above, it will be deemed that said financial operations replace the corresponding debits and credits and the tax rate will be doubled. 3 GOVERNMENT AUTHORIZATIONS AND FILINGS. Host country law and regulations in certain cases requires prior approval by the national government of any acquisition of concession and permits granting hydrocarbon rights and allowing petroleum operations to be conducted. In Argentina, Section 72 of Hydrocarbons Law 17,319 provides that permits and concessions granted under this law may be assigned with the prior authorization of the Government to assignees who meet the conditions required to be a concession holder. Such prior approval of the Government would be required if the permits and concessions held by Devon were transferred directly to a purchaser as assets. However, according to the past practice of the Secretariat of Energy, indirect transfers of permits and concessions by sale of the stock have not been subject to the prior approval of the Government. Subject to certain exemptions, Section 8 of Antitrust Law 25,156 as amended by Section 2 of National Executive Branch Decree No. 396/01, provides that the purchase of the property or any other right to shares or capital participations must be notified to the Comision Nacional de Defensa de la Competencia before execution or within a week after the transaction is closed, where the total volume of business of the participating companies exceeds US $200,000,000 in Argentina. ITEM 2. PROPERTIES OPERATION OF PROPERTIES The "Gulf Division" section under Item 2. Properties, Operation of Properties has been replaced in its entirety with the following: GULF DIVISION Devon is one of the 10 largest oil and gas producers in the offshore Gulf of Mexico. The Santa Fe Snyder merger nearly doubled Devon's asset base in the Gulf. The offshore Gulf is a prolific producing area that provides approximately 25% of the natural gas produced in the United States. The Gulf is comprised of two major operating areas, as defined by water depth. The shallow area, in water depths up to 600 feet, is known as the "shelf." Devon has a substantial infrastructure of platforms and production facilities on the shelf, where natural gas wells are known for providing high initial flow rates and quick investment returns. Devon holds approximately 650,000 net acres on the shelf, about 50% of which is developed. Devon is especially optimistic about the application of Four Component (4C) 3D seismic for both exploration and exploitation. In the West Cameron South Area, Offshore Louisiana, Devon underwrote the acquisition and processing of over 40 blocks of 4C 3D seismic due to a large producing and exploratory acreage position. A similar survey is underway in the Eugene Island area. Significant advantages accrue when oil and gas prospects and potential infield drill sites are evaluated with both conventional compressional wave (P-wave) seismic data and converted shear wave (C-wave) seismic data rather than with P-wave data only. The combination of P-wave and C-wave seismic data provides geologic insights that cannot be provided by 4 conventional P-wave data alone. The structural picture beneath shallow gas fields becomes very clear using 4-C data sets. Salt imaging is also clarified using this technique which is extremely important in the deep Eugene Island area. One of the more important characteristics of C-wave data is that it will not respond to fluid in the pore spaces of rock and responds to the matrix of the rock. This was tested by Devon initially, by recording 2D 4C seismic over known shallow gas reservoirs for the response to insitu hydrocarbon. The P-wave and C-wave data were compared. The gross distortion to the P-wave from the shallow gas was not seen on the C-wave data. The large velocity pull down was not on the C-wave data and the deep structural configuration was evident. The bright spots associated with these gas accumulations on the P-wave data were not evident on the C-wave data making for an excellent discriminator for true hydrocarbon anomalies. This approach is currently being employed by Devon. An exploitation well is planned for the fourth quarter of this year in the WC-560 field area. The A-8 well will be drilled testing a P-wave amplitude in the D. Brouweri section that is not seen on the C-wave data. This is using the shear waves as a discriminator and indicating a probable 25 BCF gas accumulation. Devon is actively developing other aspects of this cutting edge technology. The stratigraphic information that is contained in C-wave data needs to be unlocked for a powerful exploration tool, and the depth to geopressured formations can be interpreted more readily from inverted C-wave data. While the shelf is a very mature area, the deep water of the Gulf is believed to hold some of the largest remaining undiscovered reserves in North America. Devon holds about 400,000 net acres in the deep water, of which about 90% is unexplored. Because costs are much higher to explore in the deep water than on the shelf, the company's strategy is to move cautiously into deep water drilling. Devon expects to participate in three to four deep water exploratory wells per year. The Gulf Division also holds about 300,000 net acres onshore in south Texas and south Louisiana. About 80% of that acreage is developed for oil and gas production. Last year was a turnaround year for the Gulf Division onshore. Most of the onshore acreage was acquired in Devon's merger with PennzEnergy in 1999. As PennzEnergy was focused elsewhere, this acreage had received little attention in recent years. An active onshore drilling program in 2000 resulted in 14 net wells. This year we will more than double that number to a planned 38 net wells. A notable discovery in 2000 was in the Patterson Field in south Louisiana. Devon's Zenor A-16 (50% working interest) was tested at over 20 million cubic feet of natural gas per day. 5 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 1998 through 2000. Reference is made to "Item 6. Selected Financial Data" and "Item 8. Financial Statements and Supplementary Data." The "Overview" and "Results of Operations" sections under Item 7 have been replaced in its entirety with the following: OVERVIEW On May 25, 2000, Devon and Santa Fe Snyder Corporation announced their intent to merge. The transaction closed on August 29, 2000. The merger with Santa Fe Snyder was the largest transaction in Devon's history. As a result of the transaction, Devon issued approximately 40.6 million shares of common stock and assumed $730.9 million of long-term debt and $492.7 million of other liabilities. The merger increased Devon's proved reserves by 386.3 million barrels, or 58%, and the company's undeveloped leasehold by 16 million acres, or 99%. The merger with Santa Fe Snyder significantly expanded Devon's operations. However, another significant contributing factor to Devon's growth over the last three years was the company's 1999 acquisition of PennzEnergy Company ("PennzEnergy"). The acquisition of PennzEnergy added 396 million Boe of reserves, 13 million net acres of undeveloped leasehold and $3.2 billion of assets to Devon's balance sheet. In exchange, 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 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. On December 10, 1998, Devon and Northstar Energy Corporation ("Northstar") completed their merger. The combination of Devon and Northstar 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 mergers and acquisitions, Devon's exploration and development efforts have also been significant contributors to Devon's growth. In 1998 and 1999, before the merger with Santa Fe Snyder, Devon spent approximately $0.5 billion in its exploration, drilling and development efforts. These costs included drilling 1,233 wells, of which 1,137 were completed as producers. In 2000, Devon and Santa Fe Snyder combined spent $0.9 billion in its exploration, drilling and development efforts. These costs included drilling 1,328 wells, of which 1,261 were completed as producers. Devon's merger with Santa Fe Snyder was accounted for under the pooling-of-interests method of accounting for business combinations. Accordingly, Devon's prior years' results have 6 been restated to combine such results with those of Santa Fe Snyder for all years presented. Thus, the three-year comparisons of various production, revenue and expense items presented later in this section are shown as if Devon and Santa Fe Snyder had been combined for all such periods. Although this is consistent with the financial presentation of the merger, it disguises the substantial changes in Devon's operations that have occurred as a result of that transaction. To present the effects that Devon's merger with Santa Fe Snyder, the acquisition of PennzEnergy and Devon's drilling and development activities have had on operations during the last three years, the following statistics have been developed. This data assumes that Devon's merger with Santa Fe Snyder was closed at the beginning of 2000, but that prior year results were not restated. Thus, it compares Devon's 2000 results, including Santa Fe Snyder, to those of 1998 for Devon only, without Santa Fe Snyder. Such comparison yields the following fluctuations: o Combined oil, gas and NGL production increased 85.0 million Boe, or 236%. o Average combined price of oil, gas and NGL increased by $11.68 per Boe, or 108%. o Total revenues increased $2.3 billion, or 599%. o Net cash provided by operating activities increased $1.4 billion, or 745%. Cash margin increased $1.6 billion, or 853%. o Net earnings increased $790.6 million. o Earnings per share increased to $5.50 per diluted share from a loss of $1.25 per diluted share in 1998. During 2000, Devon marked its twelfth anniversary as a public company. While Devon has consistently increased production over this twelve-year period, volatility in oil and gas prices has resulted in considerable variability in earnings and cash flows. Prices for oil, natural gas and NGL 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 initial 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 twelve-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. 7 RESULTS OF OPERATIONS The following discussion of Devon's results of operations from 1998 through 2000 include the restated results of Devon for the 2000 merger with Santa Fe Snyder and the 1998 combination with Northstar, both of which were accounted for using the pooling-of-interests method. Devon's total revenues have risen from $706.2 million in 1998 to $2.8 billion in 2000. In each of these three years, oil, gas and NGL sales accounted for over 96% of total revenues. Changes in oil, gas and NGL production, prices and revenues from 1998 to 2000 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)

TOTAL --------------------------------------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 ----------- ------- --------- ------- ------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls)....................... 42,561 +34% 31,756 +24% 25,628 Gas (MMcf)........................ 426,146 +40% 304,203 +54% 198,051 NGL (MBbls)....................... 7,400 +45% 5,111 +67% 3,054 Oil, gas and NGL (MBoe)........... 120,985 +38% 87,568 +42% 61,691 REVENUES Per Unit of Production: Oil (per Bbl)................... $ 25.35 +43% 17.67 +46% 12.10 Gas (per Mcf)................... $ 3.49 +69% 2.06 +18% 1.75 NGL (per Bbl)................... $ 20.87 +57% 13.30 +64% 8.09 Oil, gas and NGL (per Boe)...... $ 22.47 +57% 14.35 +30% 11.05 Absolute: Oil............................. $ 1,078,759 +92% 561,018 +81% 309,990 Gas............................. $ 1,485,221 +137% 627,869 +81% 347,273 NGL............................. $ 154,465 +127% 67,985 +175% 24,715 ----------- --------- ------- Oil, gas and NGL................ $ 2,718,445 +116% 1,256,872 +84% 681,978 =========== ========= =======

8

DOMESTIC --------------------------------------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 ----------- ------- --------- ------- ------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls)....................... 28,562 +60% 17,822 +45% 12,257 Gas (MMcf)........................ 355,087 +61% 221,061 +82% 121,419 NGL (MBbls)....................... 6,702 +52% 4,396 +78% 2,468 Oil, gas and NGL (MBoe)........... 94,445 +60% 59,062 +69% 34,962 REVENUES Per Unit of Production: Oil (per Bbl)................... $ 25.45 +37% 18.64 +50% 12.43 Gas (per Mcf)................... $ 3.67 +62% 2.27 +12% 2.02 NGL (per Bbl)................... $ 20.30 +55% 13.11 +63% 8.05 Oil, gas and NGL (per Boe)...... $ 22.95 +52% 15.10 +26% 11.94 Absolute: Oil............................. $ 726,897 +119% 332,219 +118% 152,297 Gas............................. $ 1,304,626 +160% 501,841 +105% 245,145 NGL............................. $ 136,048 +136% 57,610 +190% 19,871 ----------- ------- ------- Oil, gas and NGL................ $ 2,167,571 +143% 891,670 +114% 417,313 =========== ======= =======

CANADA --------------------------------------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 ----------- ------- --------- ------- ------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls)....................... 4,760 (8)% 5,178 (17)% 6,257 Gas (MMcf)........................ 62,284 (15)% 73,561 +10% 67,158 NGL (MBbls)....................... 682 (3)% 700 +24% 566 Oil, gas and NGL (MBoe)........... 15,823 (13)% 18,138 +1% 18,016 REVENUES Per Unit of Production: Oil (per Bbl)................... $ 24.46 +58% 15.51 +29% 12.07 Gas (per Mcf)................... $ 2.71 +75% 1.55 +16% 1.34 NGL (per Bbl)................... $ 26.51 +84% 14.39 +75% 8.20 Oil, gas and NGL (per Boe)...... $ 19.18 +70% 11.27 +20% 9.43 Absolute: Oil............................. $ 116,427 +45% 80,298 +6% 75,493 Gas............................. $ 169,032 +48% 114,128 +27% 89,828 NGL............................. $ 18,078 +79% 10,075 +117% 4,644 ----------- ------- ------- Oil, gas and NGL................ $ 303,537 +48% 204,501 +20% 169,965 =========== ======= =======

9

INTERNATIONAL --------------------------------------------------------------------- YEAR ENDED DECEMBER 31, --------------------------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 ----------- ------- --------- ------- ------- (ABSOLUTE AMOUNTS IN THOUSANDS) PRODUCTION Oil (MBbls)....................... 9,239 +6% 8,756 +23% 7,114 Gas (MMcf)........................ 8,775 (8)% 9,581 +1% 9,474 NGL (MBbls)....................... 16 +7% 15 (25)% 20 Oil, gas and NGL (MBoe)........... 10,717 +3% 10,368 +19% 8,713 REVENUES Per Unit of Production: Oil (per Bbl)................... $ 25.48 +50% 16.96 +47% 11.55 Gas (per Mcf)................... $ 1.32 +6% 1.24 (5)% 1.30 NGL (per Bbl)................... $ 21.19 +6% 20.00 +100% 10.00 Oil, gas and NGL (per Boe)...... $ 23.08 +49% 15.50 +43% 10.87 Absolute: Oil............................. $ 235,435 +59% 148,501 +81% 82,200 Gas............................. $ 11,563 (3)% 11,900 (3)% 12,300 NGL............................. $ 339 +13% 300 +50% 200 ----------- ------- ------ Oil, gas and NGL................ $ 247,337 +54% 160,701 +70% 94,700 =========== ======= ======

OIL REVENUES 2000 vs. 1999 Oil revenues increased $517.7 million in 2000. Oil revenues increased $326.8 million due to a $7.68 per barrel increase in the average price of oil in 2000. An increase in 2000's production of 10.8 million barrels caused oil revenues to increase by $190.9 million. The PennzEnergy merger accounted for 6.8 million barrels of the 10.8 million barrel increase in production. The 2000 period included twelve months of production from the properties acquired in the 1999 PennzEnergy merger, while the 1999 period only included production for 4 1/2 months following the August 17, 1999 merger closing. Additionally, drilling activity and less significant acquisitions, offset in part by property dispositions and natural declines, caused a 4.0 million barrel increase in production. 1999 vs. 1998 Oil revenues increased $251.0 million in 1999. Oil revenues increased $176.9 million due to a $5.57 per barrel increase in the average price of oil in 1999. An increase in 1999's production of 6.1 million barrels caused oil revenues to increase by $74.1 million. The August 1999 PennzEnergy merger added 5.3 million barrels of production during the last 4 1/2 months of 1999, and the Snyder merger added 1.1 million barrels of production during the last eight months of 1999. This increase was partially offset by a 0.3 million barrel decline in 1999 production from Devon's other properties. GAS REVENUES 2000 vs. 1999 Gas revenues increased $857.4 million in 2000. A 121.9 Bcf increase in production in 2000 added $251.7 million of gas revenues compared to 1999. A $1.43 per Mcf increase in the average gas price in 2000 contributed $605.7 million of the increase in gas revenues. The PennzEnergy merger accounted for 89.3 Bcf of the 121.9 Bcf increase in consolidated production. All of the 89.3 Bcf added by the PennzEnergy merger was attributable to domestic properties. Production from Devon's other domestic properties increased 44.7 Bcf, due primarily to additional development and acquisitions, net of natural declines and dispositions. 10 Canadian gas production decreased 11.3 Bcf, or 15%, in 2000. Natural decline, increased royalty rates and dispositions of certain properties were the primary reasons for the production decline. Whereas domestic royalty rates are fixed percentages, the Canadian royalties are based on a sliding scale. As prices increased in 2000, the Canadian government's royalty percentage also increased, causing Devon's net production to decrease. Gross Canadian gas production, before royalties, was 83.4 Bcf in 2000 compared to 92.1 Bcf in 1999. 1999 vs. 1998 Gas revenues increased $280.6 million in 1999. A 106.2 Bcf increase in production in 1999 added $186.1 million of gas revenues compared to 1998. A $0.31 per Mcf increase in the average gas price in 1999 contributed $94.5 million of the increase in gas revenues. The production increase was primarily related to the PennzEnergy and Snyder mergers. The PennzEnergy properties added 55.5 Bcf of production during the 4 1/2 months following the PennzEnergy merger. The Snyder properties added 36.9 Bcf of production during the last eight months following the May 1999 Snyder merger. A 6.4 Bcf increase in Devon's Canadian gas production also contributed to the increase in 1999 gas production. NGL REVENUES 2000 vs. 1999 NGL revenues increased $86.5 million in 2000. An increase in 2000's average price of $7.57 per barrel caused NGL revenues to increase $56.0 million. A production increase of 2.3 million barrels in 2000 caused revenues to increase $30.5 million. The 1999 PennzEnergy merger accounted for 2.5 million barrels of increased NGL production in 2000. This increase was partially offset by a 0.2 million barrel reduction in 2000 production from Devon's other properties. This reduction was caused by property dispositions and natural decline, offset in part by drilling activity and property acquisitions. 1999 vs. 1998 NGL revenues increased $43.3 million in 1999. An increase in 1999's average price of $5.21 per barrel caused NGL revenues to increase $26.6 million. A production increase of 2.1 million barrels in 1999 caused revenues to increase $16.7 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. OTHER REVENUES 2000 vs. 1999 Other revenues increased $45.1 million, or 219% in 2000. Increases in third party gas processing income of $17.4 million and interest income of $4.8 million were the primary reasons for the substantial increase in other revenues. Additionally, the 2000 period included $18.4 million of dividend income from the 7.1 million shares of Chevron Corporation common stock acquired in the 1999 PennzEnergy merger. The 1999 period included $6.7 million of dividend income on these same shares. 1999 vs. 1998 Other revenues decreased $3.7 million in 1999. Other revenues in 1998 included $8.8 million of one-time revenues recognized by Northstar in 1998 from terminations of certain management agreements and gas contracts, and $4.7 million of interest income from federal income tax audits recognized by Santa Fe Snyder. In comparing 1999 to 1998, these nonrecurring 1998 revenues more than offset increases of $9.8 million in 1999 from other sources of revenues, including dividend income, interest income and third-party gas processing revenues. 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. 11 EXPENSES The details of the changes in pre-tax expenses between 1998 and 2000 are shown in the table below.

YEAR ENDED DECEMBER 31, --------------------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 ------------ ------- ---------- ------- --------- (ABSOLUTE AMOUNTS IN THOUSANDS) Absolute: Production and operating expenses: Lease operating expenses.......................... $ 440,780 +48% 298,807 +32% 226,561 Transportation costs.............................. 53,309 +57% 33,925 +46% 23,186 Production taxes.................................. 103,244 +131% 44,740 +80% 24,871 Depreciation, depletion and amortization of oil and gas properties.......................... 662,890 +70% 390,117 +69% 230,419 Amortization of goodwill............................ 41,332 +157% 16,111 N/M -- ---------- ---------- --------- Subtotal........................................ 1,301,555 +66% 783,700 +55% 505,037 Depreciation and amortization of non-oil and gas properties.................................... 30,450 +87% 16,258 +28% 12,725 General and administrative expenses................. 93,008 +15% 80,645 +77% 45,454 Expenses related to mergers......................... 60,373 +259% 16,800 +28% 13,149 Interest expense.................................... 154,329 +41% 109,613 +152% 43,532 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt 2,408 N/M (13,154) N/M 16,104 Distributions on preferred securities of subsidiary trust.................................. -- (100)% 6,884 (29)% 9,717 Reduction of carrying value of oil and gas properties........................................ -- (100)% 476,100 +13% 422,500 ---------- ---------- --------- Total........................................... $1,642,123 +11% 1,476,846 +38% 1,068,218 ========== ========== ========= Per Boe: Production and operating expenses: Lease operating expenses.......................... $ 3.65 +7% 3.41 (7)% 3.67 Transportation costs.............................. 0.44 +13% 0.39 +3% 0.38 Production taxes.................................. 0.85 +67% 0.51 +28% 0.40 Depreciation, depletion and amortization of oil and gas properties.......................... 5.48 +23% 4.46 +19% 3.74 Amortization of goodwill............................ 0.34 +89% 0.18 N/M -- ---------- ---------- --------- Subtotal........................................ 10.76 +20% 8.95 +9% 8.19 Depreciation and amortization of non-oil and gas properties (1)................................ 0.25 +32% 0.19 (10)% 0.21 General and administrative expenses (1)............. 0.77 (16)% 0.92 +24% 0.74 Expenses related to prior mergers (1)............... 0.50 +163% 0.19 (10)% 0.21 Interest expense (1)................................ 1.27 +2% 1.25 +79% 0.70 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt (1) 0.02 N/M (0.15) N/M 0.26 Distributions on preferred securities of subsidiary trust (1).............................. -- (100)% 0.08 (50)% 0.16 Reduction of carrying value of oil and gas properties (1).................................... -- (100)% 5.44 (21)% 6.85 ---------- ---------- --------- Total............................................ $ 13.57 (20)% 16.87 (3)% 17.32 ========== ========== =========

---------- (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. N/M - Not meaningful. 12 PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expenses between 1998 and 2000 are shown in the table below.

TOTAL ---------------------------------------------------------- YEAR ENDED DECEMBER 31, ---------------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 --------- ------- -------- ------- -------- (ABSOLUTE AMOUNTS IN THOUSANDS) Absolute: Recurring lease operating expenses........... $ 422,853 +45% 291,037 +33% 219,316 Well workover expenses....................... 17,927 +131% 7,770 +7% 7,245 Transportation costs......................... 53,309 +57% 33,925 +46% 23,186 Production taxes............................. 103,244 +131% 44,740 +80% 24,871 ---------- --------- -------- Total production and operating expenses $ 597,333 +58% 377,472 +37% 274,618 ========== ========= ======== Per Boe: Recurring lease operating expenses........... $ 3.50 +5% 3.32 (7)% 3.56 Well workover expenses....................... 0.15 +67% 0.09 (18)% 0.11 Transportation costs......................... 0.44 +13% 0.39 +3% 0.38 Production taxes............................. 0.85 +67% 0.51 +28% 0.40 ---------- --------- -------- Total production and operating expenses... $ 4.94 +15% 4.31 (3)% 4.45 ========== ========= ========

2000 vs. 1999 Recurring lease operating expenses increased $131.8 million, or 45%, in 2000. The 1999 PennzEnergy merger accounted for $92.4 million of the increase in expenses. Additionally, $11.0 million of costs were added by the August 1999 and January 2000 acquisitions of certain properties and $7.7 million of costs were added by the Snyder merger. Other than the added costs from these acquisitions, Devon's recurring costs increased $20.7 million in 2000. This increase was primarily caused by increased production and higher ad valorem taxes and fuel costs. Transportation costs represent those costs paid directly to third-party providers to transport oil and gas production sold downstream from the wellhead. Transportation costs increased $19.4 million, or 57% in 2000 primarily due to increased production. The majority of Devon's production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 143% increase in domestic oil, gas and NGL revenues was the primary cause of a 136% 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 oil and 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. 1999 vs. 1998 Recurring lease operating expenses increased $71.7 million, or 33%, in 1999. The PennzEnergy properties added $57.3 million of expenses in the last 4 1/2 months of the year, and the Snyder properties added $17.7 million of expenses for the last eight months of the year. Other than the added costs from the PennzEnergy and Snyder properties, recurring expenses on Devon's other properties dropped $3.3 million in 1999. Efficiencies achieved in certain of Devon's oil producing properties contributed a substantial portion of this cost reduction. 13 Transportation costs increased $10.7 million, or 46% in 1999 primarily due to increased production. As previously stated, most of the U.S. production taxes are based on a fixed percentage of revenues. Therefore, the 114% increase in domestic oil, gas and NGL revenues was the primary cause of a 88% increase 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. 2000 vs. 1999 Oil and gas property related DD&A increased $272.8 million, or 70%, in 2000. Oil and gas property related DD&A increased $148.9 million due to the 38% increase in oil, gas and NGL production in 2000. Oil and gas property related DD&A increased $123.9 million due to an increase in the consolidated DD&A rate. The consolidated DD&A rate increased from $4.46 per Boe in 1999 to $5.48 per Boe in 2000. Non-oil and gas property DD&A increased $14.2 million in 2000 compared to 1999. Depreciation of the non-oil and gas properties acquired in the PennzEnergy and Snyder mergers and depreciation of Devon's new Wyoming gas pipeline and gathering system, accounted for the increase in 2000's expense. 1999 vs. 1998 Oil and gas property related DD&A increased $159.7 million, or 69%, in 1999. Oil and gas property related DD&A increased $96.7 million due to the 42% increase in oil, gas and NGL production in 1999. Oil and gas property related DD&A increased $63.0 million due to an increase in the consolidated DD&A rate. The consolidated DD&A rate increased from $3.74 per Boe in 1998 to $4.46 per Boe in 1999. The 1999 rate of $4.46 per Boe was a blended rate of before and after the PennzEnergy and Snyder mergers. Non-oil and gas property DD&A increased $3.5 million in 1999 compared to 1998. Depreciation of the non-oil and gas properties acquired in the PennzEnergy and Snyder mergers and depreciation of Devon's new Wyoming gas pipeline and gathering system, accounted for the increase in 1999's expense. AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger, Devon recorded $346.9 million of goodwill. The goodwill was allocated $299.5 million to domestic operations and $47.4 million to international operations. The goodwill is being amortized using the units-of-production method. Substantially all of the $41.3 million and $16.1 million of amortization recognized in 2000 and 1999, respectively, was related to the domestic balance. 14 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 the following table for a summary of G&A expenses by component.

TOTAL ----------------------------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 2000 vs 1999 1999 vs 1998 1998 ---------- ------- -------- ------- -------- (IN THOUSANDS) Gross G&A............................ $ 205,693 +37% 150,441 +57% 95,589 Capitalized G&A...................... (61,764) +114% (28,878) +95% (14,812) Reimbursed G&A....................... (50,921) +24% (40,918) +16% (35,323) --------- ------- ------- Net G&A.......................... $ 93,008 +15% 80,645 +77% 45,454 ========= ======= =======

2000 vs. 1999 Net G&A increased $12.4 million in 2000. Gross G&A increased $55.3 million in 2000 compared to 1999. The increase in gross expenses was primarily related to additional costs incurred as a result of the 1999 PennzEnergy and Snyder mergers. G&A was reduced $32.9 million in 2000 due to an increase in the amount capitalized as part of oil and gas properties. G&A was also reduced $10.0 million in 2000, by an increase in the amount of reimbursements on operated properties in the 2000 period. The increase in capitalized and reimbursed G&A was primarily related to the 1999 PennzEnergy and Snyder mergers. 1999 vs. 1998 Net G&A increased $35.2 million in 1999. Gross G&A increased $54.9 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. G&A was lowered $14.1 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 $5.6 million increase in the amount of reimbursements on operated properties. The 1999 reimbursements received from the PennzEnergy properties were $6.0 million. The increase, in absolute terms, in capitalized general and administrative expenses from 1999 to 2000 was primarily a result of the 1999 PennzEnergy and 2000 Snyder mergers. Only 4 1/2 and 7 months of expenses related to the PennzEnergy and Snyder mergers, respectively, were included in 1999. The increase, on a percentage basis, in capitalized general and administrative expenses from 1999 to 2000 was primarily related to an increase in acquisition, exploration and development activities from 1999 to 2000. In 1999, Santa Fe Snyder experienced capital constraints as a result of lower commodity prices. This led to a reduction in acquisition, exploration and development activities, especially as it related to its international assets. (The 15 capital constraints were also one of the considerations in Santa Fe's decision to merge with Devon in 2000.) In 2000, with improving commodity prices and after the announcement of the merger in May 2000, more money was being spent on acquisition, exploration and development activities, overall, but especially on the international assets. This is further evidenced by the increase in capital expenditures from 1999 to 2000. Total capital expenditures were $883.4 million in 1999 compared to $1,280.1 million in 2000. International capital expenditures were $104.9 million in 1999 compared to $184.4 million in 2000. These same considerations took place in the U.S. and Canada also, though the effects were not as significant. Overall, the rising commodity prices in 2000 allowed Devon, and Santa Fe Snyder prior to its merger with Devon, to focus more resources on acquisition, exploration and development activities as compared to 1999. This increase in acquisition, exploration and development activities meant that a larger percentage of general and administrative costs specifically related to such activities were subject to capitalization. EXPENSES RELATED TO MERGERS Approximately $60.4 million of expenses were incurred in 2000 in connection with the Santa Fe Snyder merger. These expenses consisted primarily of severance and other benefit costs, investment banking fees, other professional expenses, costs associated with duplicate facilities and various transaction related costs. 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. Approximately $16.8 million of expenses were incurred by Santa Fe Snyder in 1999 related to the Snyder merger. These costs included $14.4 million related to compensation plans and other benefits, and $1.9 million of severance and relocation costs. The $16.8 million of costs related to the operations and employees of the former Santa Fe Energy Resources, Inc., not those of the former Snyder Oil Corporation. Therefore, the costs were required to be expensed as opposed to capitalized as part of the Snyder merger. 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. INTEREST EXPENSE 2000 vs. 1999 Interest expense increased $44.7 million, or 41%, in 2000. An increase in the average debt balance outstanding from $1.5 billion in 1999 to $2.3 billion in 2000 caused interest expense to increase by $53.7 million. The increase in average debt outstanding in 2000 was attributable to the long-term debt assumed in the Snyder and PennzEnergy mergers on May 5, 1999 and August 17, 1999, respectively. The average interest rate on outstanding debt decreased from 7.0% in 1999 to 6.7% in 2000. This rate decrease caused interest expense to decrease $4.7 million in 2000. 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 $4.3 million lower in 2000 compared to 1999. 1999 vs. 1998 Interest expense increased $66.1 million in 1999. An increase in the average debt balance outstanding from $588.3 million in 1998 to $1.5 billion in 1999 caused interest expense to increase by $69.9 million. The increase in average debt outstanding in 1999 was attributable to the long-term debt assumed in the Snyder and PennzEnergy mergers on 16 May 5, 1999 and August 17, 1999, respectively. The average interest rate on outstanding debt decreased from 7.3% in 1998 to 7.0% in 1999. This rate decrease caused interest expense to decrease $4.9 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 $1.1 million higher in 1999 compared to 1998. DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT 2000 vs. 1999 Until mid-January 2000, Devon's Canadian subsidiary Northstar Energy Corporation 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 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 were required to be included in determining net earnings for the period in which the exchange rate changed. 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. 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 2000. 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. DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed in Note 9 to the consolidated financial statements, 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. 2000 vs. 1999 There were no TCP Securities distributions in 2000 compared to $6.9 million in 1999. Substantially all of the TCP Securities were exchanged for shares of Devon common stock on November 30, 1999. 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. 17 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. Devon did not reduce the carrying value of its oil and gas properties in 2000. During 1999 and 1998, Devon reduced the carrying value of its oil and gas properties by $476.1 million and $422.5 million, respectively, due to the full-cost ceiling limitations. The after-tax effect of these reductions in 1999 and 1998 were $309.7 million and $280.8 million, respectively. INCOME TAXES 2000 vs. 1999 Devon's 2000 financial tax expense rate was 36% of income 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 foreign income taxes, offset in part by the recognition of a benefit from the disposition of Devon's assets in Venezuela. The 1999 financial tax benefit rate was 25%. This rate was lower 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 foreign income taxes. 1999 vs. 1998 Devon's 1999 financial tax benefit rate was 25% of loss before income tax benefit. This rate was lower 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 foreign income taxes. The 1998 financial tax benefit rate was 35%. CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the supplemental consolidated statements of cash flows included elsewhere in this report. CAPITAL EXPENDITURES Approximately $1.3 billion was spent in 2000 for capital expenditures, of which $1.2 billion was related to the acquisition, drilling or development of oil and gas properties. These amounts compare to 1999 total expenditures of $883.4 million ($784.9 million of which was related to oil and gas properties) and 1998 total expenditures of $712.8 million ($704.6 million of which was related to oil and gas properties.) OTHER CASH USES Devon's common stock dividends were $22.2 million, $12.7 million and $7.3 million in 2000, 1999 and 1998, respectively. Devon also paid $9.7 million of preferred stock dividends in 2000 and $3.7 million in the last 4 1/2 months of 1999 following the PennzEnergy merger. 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 $1.6 billion, $532.3 million and $334.5 million in 2000, 1999 and 1998, 18 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 2000 and 1999, debt repayments exceeded borrowings by $371.6 million and $144.7 million, respectively. During 1998, long-term debt borrowings exceeded repayments by $264.2 million. Prior to the August 2000 merger, Devon and Santa Fe Snyder each had their own unsecured credit facilities. Devon's credit facilities prior to the merger aggregated $750 million, with $475 million in a U.S. facility and $275 million in a Canadian facility. These Devon credit facilities were entered into in October 1999. Santa Fe Snyder's credit facilities prior to the merger aggregated $600 million. Concurrent with the closing of the Santa Fe Snyder merger on August 29, 2000, Devon entered into new unsecured long-term credit facilities aggregating $1 billion (the "Credit Facilities"). The Credit Facilities replaced the prior separate facilities of Devon and Santa Fe Snyder. The Credit Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The $725 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $525 million. The Tranche B facility can be increased to as high as $625 million and reduced to as low as $425 million by reallocating the amount available between the Tranche B facility and the Canadian Facility. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until August 28, 2001 (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. As of December 31, 2000, Devon had no borrowings under its U.S. Facility. Devon may borrow funds under the $275 million Canadian Facility until August 28, 2001 (the "Canadian Facility Revolving Period"). As disclosed in the prior paragraph, the Canadian Facility can be increased to as high as $375 million and reduced to as low as $175 million by reallocating the amount available between the Tranche B facility and the Canadian Facility. 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. As of December 31, 2000, Devon had $146.7 million borrowed under its Canadian Facility at a weighted average interest rate of 6.1%. 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, and are tied to margins determined by Devon's corporate credit ratings. Devon may also 19 elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly. On August 29, 2000, Devon entered into a commercial paper program. Total borrowings under the U.S. credit facility and the commercial paper program may not exceed $725 million. The commercial paper borrowings may have terms of up to 365 days and bear interest at rates agreed to at the time of the borrowing. The interest rate will be based on a standard index such as the Federal Funds Rate, London Interbank Offered Rate (LIBOR), or the money market rate as found on the commercial paper market. As of December 31, 2000, Devon had no borrowings under its commercial paper program. In June 2000, Devon privately sold zero coupon convertible senior debentures. The convertible debentures were sold at a price of $464.13 per debenture with a yield to maturity of 3.875% per annum. Each of the 760,000 debentures is convertible into 5.7593 shares of Devon common stock. Devon may call the debentures at any time after five years, and a debenture holder has the right to require Devon to repurchase the debentures after five, 10 and 15 years, at the issue price plus accrued original issue discount and interest. The proceeds to Devon were approximately $346.1 million, net of debt issuance costs of approximately $6.6 million. Devon used the proceeds from the sale of these convertible debentures to pay down other domestic long-term debt. 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. Also, Santa Fe Snyder raised $108 million in 1999 from an equity offering of its common stock following its merger with Snyder. 2001 ESTIMATES The forward-looking statements provided in this discussion are based on management's examination of historical operating trends, the information which was used to prepare the December 31, 2000 reserve reports of independent petroleum engineers and other data in Devon's possession or available from third parties. Devon cautions that its future oil, natural gas and NGL 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, the 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 NGL 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 NGL prices may 20 vary considerably due to differences between regional markets, transportation availability and demand for different grades of oil, gas and NGL. 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. Estimates for Devon's future production of oil, natural gas and NGL 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. Also, Devon's International production of oil, natural gas and NGL is governed by payout agreements with the governments of the countries in which Devon operates. If the payout under these agreements is attained earlier than projected, Devon's net production and proved reserves in such areas could be reduced. The production, transportation and marketing of oil, natural gas and NGL 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 NGL during 2001 will be substantially similar to those of 2000, unless otherwise noted. Given the general limitations expressed herein, Devon's forward-looking statements for 2001 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 an exchange rate of $0.6695 U.S. dollar to $1.00 Canadian dollar. The actual 2001 exchange rate may vary materially from this estimated rate. Such variations could have a material effect on the following Canadian estimates. GEOGRAPHIC REPORTING AREAS FOR 2001 The following estimates of production, average price differentials and capital expenditures are provided separately for each of Devon's geographic divisions. These divisions are as follows: o the Gulf Division, which operates oil and gas properties located primarily in the onshore South Texas and South Louisiana areas and offshore in the Gulf of Mexico; o the Rocky Mountain Division, which operates oil and gas properties located in the Rocky Mountains area of the United States stretching from the Canadian border south into northern New Mexico; o the Permian/Mid-Continent Division, which operates all properties located in the United States other than those operated by the Gulf Division and the Rocky Mountain Division; o Canada; and o International Division, which encompasses all oil and gas properties that lie outside of the United States and Canada. 21 YEAR 2001 POTENTIAL OPERATING ITEMS OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are individual estimates of Devon's oil, gas and NGL production in 2001. On a combined basis, Devon estimates its 2001 oil, gas and NGL production will total between 120.4 million and 128.0 million barrels of oil equivalent. Devon's estimates of 2001 production do not include certain oil, gas and NGL production from various properties that were sold during 2000. These sold properties produced approximately 2.9 million barrels of oil equivalent in 2000 that will not be produced by Devon in 2001. OIL PRODUCTION Devon expects its oil production in 2001 to total between 40.3 million barrels and 42.8 million barrels. The expected ranges of production by division are as follows:

Expected Range of Production (MMBbls) ------------------- Permian/Mid-Continent 12.2 to 12.9 Gulf 10.1 to 10.8 Rocky Mountain 3.0 to 3.2 Canadian 5.3 to 5.6 International 9.7 to 10.3

OIL PRICES - FIXED Devon has fixed the price it will receive in 2001 on a portion of its oil production through certain forward oil sales. Devon has executed forward oil sales attributable to the Permian/Mid-Continent Division for 3.7 million barrels at an average price of $16.84 per barrel. These fixed-price volumes represent 9% of Devon's expected consolidated oil production in 2001. Santa Fe Snyder Corporation entered into these forward oil sales agreements in late 1999 and early 2000, and used the proceeds to acquire interests in producing properties in the Gulf of Mexico. OIL PRICES - FLOATING For the oil production for which prices have not been fixed, Devon's 2001 average prices for each of its divisions are expected to differ from the New York Mercantile Exchange price ("NYMEX") as set forth in the following table. The NYMEX price is the monthly average of settled prices on each trading day for West Texas Intermediate Crude oil delivered at Cushing, Oklahoma.

Expected Range of Oil Prices Greater Than (Less Than) NYMEX ------------------------------ Permian/Mid-Continent ($3.10) to ($2.10) Gulf ($2.90) to ($1.90) Rocky Mountain ($2.50) to ($1.50) Canadian ($5.50) to ($4.50) International ($3.65) to ($2.65)

The above range of expected Canadian differentials compared to NYMEX includes an estimated $0.11 per barrel decrease resulting from foreign currency hedges. These hedges, in which Devon will sell $10 million in 2001 at an average Canadian-to-U.S. exchange rate of $0.7102 and buy the same amount of dollars at the floating exchange rate, offset a portion of the 22 exposure to currency fluctuations on those Canadian oil sales that are based on U.S. prices. The $0.11 per barrel decrease is based on the assumption that the average Canadian-to-U.S. conversion rate for the year 2001 is $0.6695. GAS PRODUCTION Devon expects its 2001 gas production to total between 439 Bcf and 469 Bcf. The expected ranges of production by division are as follows:

Expected Range of Production (Bcf) ---------------- Permian/Mid-Continent 114 to 121 Gulf 144 to 153 Rocky Mountain 115 to 123 Canadian 58 to 62 International 8 to 10

GAS PRICES - FIXED Through various price swaps and fixed-price physical delivery contracts, Devon has fixed the price it will receive in 2001 on a portion of its natural gas production. The following tables include information on this fixed-price production by division. Where necessary, the prices have been adjusted for certain transportation costs that are netted against the price recorded by Devon, and the price has also been adjusted for the Btu content of the gas production that has been hedged.

FIRST HALF OF 2001 SECOND HALF OF 2001 ------------------------------- ---------------------------- DIVISION Mcf/DAY PRICE/Mcf Mcf/DAY PRICE/Mcf -------- ------- --------- ------- --------- Rocky Mountain 20,661 $ 1.90 57,955 $ 3.68 Gulf -- $ -- 40,000 $ 5.45 Canada 60,011 $ 1.53 56,888 $ 1.52

Additionally, Devon has entered into a basis swap on 7.3 Bcf of 2001 gas production. Under the terms of the basis swap, the counterparty pays Devon the average NYMEX price for the last three trading days of each month, less $0.30 per Mcf. In return, Devon pays the counterparty the Colorado Interstate Gas Co. ("CIG") index price published by "Inside F.E.R.C.'s Gas Market Report" ("Inside FERC"). The effect of this swap is included in Rocky Mountain Division gas revenues. This basis swap does not qualify as a hedge under the provisions of SFAS No. 133. Accordingly, fluctuations in the fair value of this basis swap will be recorded in earnings beginning in the first quarter of 2001. GAS PRICES - FLOATING For the natural gas production for which prices have not been fixed, Devon's 2001 average prices for each of its divisions are expected to differ from NYMEX as set forth in the following table. NYMEX is determined to be the first-of-month South Louisiana Henry Hub price index as published monthly in "Inside FERC." 23

Expected Range of Gas Prices Greater Than (Less Than) NYMEX ------------------------------ Permian/Mid-Continent ($0.40) to $0.10 Gulf ($0.15) to $0.35 Rocky Mountain ($0.90) to ($0.40) Canadian ($0.85) to ($0.35) International ($2.60) to ($2.10)

Devon has also entered into a costless price collar that sets a floor and ceiling price for 20,000 MMBtu/day of Rocky Mountain Division gas production during the second half of 2001. The collar has a floor and ceiling price per MMBtu of $4.10 and $8.00, respectively. The floor and ceiling prices are based on the first-of-the-month CIG price index as published monthly by Inside FERC. If the CIG index is outside of the ranges set by the floor and ceiling prices, Devon and the counterparty to the collar will settle the difference. Any such settlements will either increase or decrease Devon's gas revenues for the period. Because Devon's gas volumes are often sold at prices that differ from related regional indices, and due to differing Btu content of gas production, the floor and ceiling prices of the collar do not reflect actual limits of Devon's realized prices for the production volumes related to the collar. NGL PRODUCTION Devon expects its 2001 production of NGL to total between 6.6 million barrels and 7.3 million barrels. The expected ranges of production by division are as follows:

Expected Range of Production (MMBbls) ------------------- Permian/Mid-Continent 4.3 to 4.6 Gulf 1.0 to 1.1 Rocky Mountain 0.6 to 0.7 Canadian 0.5 to 0.6 International 0.2 to 0.3

OTHER REVENUES Devon's other revenues in 2001 are expected to be between $53 million and $59 million. This estimated range does not include the gain or loss that could be recognized from changes in the fair values of Devon's derivatives that are not hedges. Substantially all of Devon's derivatives are hedges, but the gas price basis swap previously discussed and the option embedded in the debentures that are exchangeable into shares of Chevron Corporation common stock are not hedges. Accordingly, the changes in the fair value of these derivatives will be recognized in Devon's operating results in 2001. PRODUCTION AND OPERATING EXPENSES Devon's production and operating expenses include lease operating expenses, transportation costs and production taxes. These 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 tax rates, changes in the general price level of services and materials that are used in the operation of the properties and the amount of repair and workover activity required. Oil, natural gas and NGL prices also have an effect on lease operating expense and impact the economic feasibility of planned workover projects. 24 These factors, coupled with uncertainty of future oil, natural gas and NGL prices, increase the uncertainty inherent in estimating future production and operating costs. Given these uncertainties, Devon estimates that year 2001 lease operating expense will be between $463 million and $492 million, transportation costs will be between $62 million and $66 million and production taxes will be between 4% and 5% of consolidated oil, natural gas and NGL revenues. DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2001 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition efforts in 2001 compared to the costs incurred for such efforts, and the revisions to Devon's year-end 2000 reserve estimates that, based on prior experience, are likely to be made during 2001. In addition to oil and gas property related DD&A, Devon expects its 2001 DD&A expense related to non-oil and gas property fixed assets to total between $30 million and $32 million. Based on this range and the production estimates discussed earlier, Devon expects its 2001 consolidated DD&A rate to total between $6.15 per Boe and $6.45 per Boe. Devon also expects to record goodwill amortization in 2001 of between $33 million and $35 million. The goodwill was recorded in connection with the 1999 merger with PennzEnergy. 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 2001 is expected to be between $89 million and $98 million. INTEREST EXPENSE Future interest rates and oil, natural gas and NGL prices have a significant effect on Devon's interest expense. Approximately $1.9 billion of Devon's December 31, 2000, long-term debt balance of $2.0 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 it will receive in 2001 from sales of oil, natural gas and NGL and the resulting cash flow. 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, and assuming that the fixed-rate debt remains in place throughout the year, Devon estimates that the consolidated interest expense in 2001 will be between $143 million and $146 million. Included in this estimate is $12 million of discount accretion on the debentures that are exchangeable into shares of Chevron Corporation common stock. The discount accretion is the result of the adoption of SFAS 133 effective January 1 2001. 25 REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES As of December 31, 2000, Devon does not expect to record a reduction in 2001 of its carrying value of oil and natural gas properties under the full-cost accounting ceiling test. At this time the ceiling for each full-cost pool exceeds Devon's carrying value of oil and natural gas properties, less deferred income taxes. However, such excess could be eliminated by declines in oil and/or natural gas prices between now and the end of any quarter during 2001 or in subsequent periods. INCOME TAXES Devon expects its consolidated financial income tax rate in 2001 to be between 35% and 45%. The current income tax rate is expected to be between 20% and 25%. The deferred income tax rate is expected to be between 15% and 20%. There are certain items that will have a fixed impact on 2001'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 generated to offset financial income tax expense in 2001 is approximately $20 million. Also, Devon's Canadian subsidiaries are subject to Canada's "large corporation tax" of approximately $3 million which is based on total capitalization levels, not pre-tax earnings. The financial income tax in 2000 will also be increased by approximately $14 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 NGL, the prices of such products, or any of the various expense items could materially alter the effect of the aforementioned items on 2001's financial income tax rates. YEAR 2001 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY CAPITAL EXPENDITURES 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's capital expenditures budget is based on an expected range of future oil, natural gas and NGL 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 2001 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. Given the limitations discussed, the company expects its 2001 capital expenditures for drilling and development efforts plus related facilities to total between $1.05 billion and $1.15 billion. These amounts include between $160 million and $180 million for drilling and facilities costs related to reserves expected to be classified as proved as of year-end 2000. In addition, these amounts include between $520 million and $560 million for other low risk/reward projects and between $370 million and $410 million for new, higher risk/reward projects. The following table shows expected drilling and facilities expenditures by major operating division. 26 DRILLING AND PRODUCTION FACILITIES EXPENDITURES (MILLIONS) --------------------------------------------------------------------------- PERMIAN/ ROCKY MID- MOUNTAIN CONTINENT GULF OTHER DIVISION DIVISION DIVISION CANADA INTERNATIONAL --------- --------- --------- --------- ------------- Related to Proved Reserves $45-$55 $70-$80 $0-$10 $10-$20 $20-$30 Lower Risk/Reward Projects $45-$55 $90-$100 $185-$215 $40-$50 $140-$170 Higher Risk/Reward Projects $20-$30 $40-$50 $110-$130 $105-$125 $80-$100 --------- --------- --------- --------- --------- Total $110-$140 $200-$230 $295-$355 $155-$195 $240-$300 ========= ========= ========= ========= ========= In addition to the above expenditures for drilling and development, Devon is participating through a joint venture in the construction of gas transportation and processing systems in the Powder River Basin of Wyoming. Devon expects to spend from $15 million to $20 million as its share of the project in 2001. Devon also expects to capitalize between $70 million and $80 million of G&A expenses in accordance with the full-cost method of accounting. Devon also expects to pay between $15 million and $20 million for plugging and abandonment charges in 2001. Finally, Devon expects to spend between $15 million and $20 million for non-oil and gas property fixed assets. OTHER CASH USES Devon's management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.05 per share quarterly dividend rate and 129 million shares of common stock outstanding, 2001 dividends are expected to approximate $26 million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay $9.7 million of dividends in 2001. CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2001 cash uses, including its 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 2001 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 2001. As of December 31, 2000, Devon had $853 million available under its $1 billion 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"), and in June 2000 issued SFAS 138, which amended certain provisions of SFAS 133. SFAS 133, as amended, 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 27 derivative (that is gains and losses) depends on the intended use of the derivative and whether it qualifies as a hedge. Devon adopted the provisions of SFAS 133, as amended, in the first quarter of the year ending December 31, 2001. In accordance with the transition provisions of SFAS 133, Devon recorded a net-of-tax cumulative-effect-type adjustment of $36.6 million in accumulated other comprehensive loss to recognize at fair value all derivatives that are designated as cash-flow hedging financial instruments. Additionally, Devon recorded a net-of-tax cumulative-effect-type adjustment to net earnings for a $49.5 million gain related to the fair value of financial instruments that do not qualify as hedges. This gain included $46.2 million related to the option embedded in Devon's debentures that are exchangeable into shares of Chevron Corporation common stock. 28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Page ---- Independent Auditors' Reports............................................................................. 30 Consolidated Financial Statements: Consolidated Balance Sheets December 31, 2000, 1999, and 1998................................................................... 33 Consolidated Statements of Operations Years Ended December 31, 2000, 1999, and 1998....................................................... 34 Consolidated Statements of Stockholders' Equity Years Ended December 31, 2000, 1999, and 1998....................................................... 35 Consolidated Statements of Cash Flows Years Ended December 31, 2000, 1999, and 1998....................................................... 36 Notes to Consolidated Financial Statements December 31, 2000, 1999, and 1998................................................................... 37

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. 29 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 (the Company) as of December 31, 2000, 1999 and 1998, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of 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 1999 and 1998 financial statements of Santa Fe Snyder Corporation, a wholly-owned subsidiary, which statements reflect total assets constituting 24% and 38% in 1999 and 1998, respectively, of the related consolidated totals, and which statements reflect total revenues constituting 41% and 43% in 1999 and 1998, respectively, of the related consolidated totals. We did not audit the 1998 financial statements of Northstar Energy Corporation, a wholly-owned subsidiary, which statements reflect total assets constituting 20% of the related consolidated 1998 total, and which statements reflect total revenues constituting 22% in 1998 of the related consolidated totals. The 1999 and 1998 financial statements of Santa Fe Snyder Corporation and the 1998 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 Santa Fe Snyder Corporation in 1999 and 1998, and Northstar Energy Corporation in 1998, is based solely on the reports of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. 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, 2000, 1999 and 1998, and the results of their operations and their cash flows for each of the years then ended, in conformity with accounting principles generally accepted in the United States of America. KPMG LLP Oklahoma City, Oklahoma January 30, 2001 30 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors of Santa Fe Snyder Corporation: In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, comprehensive income, shareholders' equity and of cash flows present fairly, in all material respects, the financial position of Santa Fe Snyder Corporation and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 1999 (not separately presented herein) in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As further described in Note 2, these consolidated financial statements have been retroactively restated to the full cost method of accounting for the Company's oil and gas properties in order to conform to the accounting policies of Devon Energy Corporation. PricewaterhouseCoopers LLP Houston, Texas January 28, 2000, except for Note 2 and the second paragraph above which are as of October 30, 2000 31 AUDITORS' REPORT TO THE SHAREHOLDERS We have audited the consolidated balance sheet of Northstar Energy Corporation (a wholly owned subsidiary of Devon Energy Corporation) as at December 31, 1998 and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity and cash flows for the year ended December 31, 1998 (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 audit. We conducted our audit 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 at December 31, 1998, and the results of its operations and the changes in its cash flow for the year ended December 31, 1998 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 32 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)

DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ------------ ------------ ------------ ASSETS Current assets: Cash and cash equivalents $ 228,050 173,167 31,254 Accounts receivable 598,248 316,005 137,058 Inventories 47,272 38,941 21,750 Deferred income taxes 8,979 4,886 605 Investments and other current assets 51,588 57,295 35,981 ------------ ------------ ------------ Total current assets 934,137 590,294 226,648 ------------ ------------ ------------ Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($315,260, $301,185 and $213,577 excluded from amortization in 2000, 1999 and 1998, respectively) 9,709,352 8,592,010 4,854,211 Less accumulated depreciation, depletion and amortization 4,799,816 4,168,590 3,230,683 ------------ ------------ ------------ 4,909,536 4,423,420 1,623,528 Investment in Chevron Corporation common stock, at fair value 598,867 614,382 -- Deferred income taxes -- -- 54,381 Goodwill, net of amortization 289,489 322,800 -- Other assets 128,449 145,464 25,980 ------------ ------------ ------------ Total assets $ 6,860,478 6,096,360 1,930,537 ============ ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade 320,713 266,825 155,377 Revenues and royalties due to others 116,481 67,330 20,608 Income taxes payable 65,674 12,587 1,200 Accrued interest payable 23,191 28,370 5,588 Merger related expenses payable 52,421 35,704 7,882 Accrued expenses 50,507 56,528 29,201 ------------ ------------ ------------ Total current liabilities 628,987 467,344 219,856 ------------ ------------ ------------ Other liabilities 164,469 241,782 71,947 Debentures exchangeable into shares of Chevron Corporation common stock 760,313 760,313 -- Other long-term debt 1,288,523 1,656,208 735,871 Deferred revenue 113,756 104,800 3,600 Deferred income taxes 626,826 344,593 -- Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trust holding solely 6.5% convertible junior subordinated debentures of Devon Energy Corporation -- -- 149,500 Stockholders' equity: Preferred stock of $1.00 par value ($100 liquidation value) Authorized 4,500,000 shares; issued 1,500,000 in 2000 and 1,500 1,500 -- 1999 and none in 1998 Common stock of $.10 par value Authorized 400,000,000 shares; issued 128,638,000 in 2000, 126,323,000 in 1999 and 70,909,000 in 1998 12,864 12,632 7,090 Additional paid-in capital 3,563,994 3,491,828 1,523,944 Retained earnings (accumulated deficit) (214,708) (908,598) (737,009) Accumulated other comprehensive loss (85,397) (65,242) (35,962) Unamortized restricted stock awards (649) -- (1,500) Treasury stock, at cost: 330,000 shares in 1999 and 176,000 shares in 1998 -- (10,800) (6,800) ------------ ------------ ------------ Total stockholders' equity 3,277,604 2,521,320 749,763 ------------ ------------ ------------ Commitments and contingencies (Notes 12 and 13) Total liabilities and stockholders' equity $ 6,860,478 6,096,360 1,930,537 ============ ============ ============

See accompanying notes to consolidated financial statements. 33 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

YEAR ENDED DECEMBER 31, ----------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ REVENUES Oil sales $ 1,078,759 561,018 309,990 Gas sales 1,485,221 627,869 347,273 Natural gas liquids sales 154,465 67,985 24,715 Other 65,658 20,596 24,248 ------------ ------------ ------------ Total revenues 2,784,103 1,277,468 706,226 ------------ ------------ ------------ COSTS AND EXPENSES Lease operating expenses 440,780 298,807 226,561 Transportation costs 53,309 33,925 23,186 Production taxes 103,244 44,740 24,871 Depreciation, depletion and amortization of property and equipment 693,340 406,375 243,144 Amortization of goodwill 41,332 16,111 -- General and administrative expenses 93,008 80,645 45,454 Expenses related to mergers 60,373 16,800 13,149 Interest expense 154,329 109,613 43,532 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt 2,408 (13,154) 16,104 Distributions on preferred securities of subsidiary trust -- 6,884 9,717 Reduction of carrying value of oil and gas properties -- 476,100 422,500 ------------ ------------ ------------ Total costs and expenses 1,642,123 1,476,846 1,068,218 ------------ ------------ ------------ Earnings (loss) before income tax expense (benefit) and extraordinary item 1,141,980 (199,378) (361,992) INCOME TAX EXPENSE (BENEFIT) Current 130,793 23,056 (3,713) Deferred 280,845 (72,490) (122,394) ------------ ------------ ------------ Total income tax expense (benefit) 411,638 (49,434) (126,107) ------------ ------------ ------------ Earnings (loss) before extraordinary item 730,342 (149,944) (235,885) Extraordinary loss -- (4,200) -- ------------ ------------ ------------ Net earnings (loss) 730,342 (154,144) (235,885) Preferred stock dividends 9,735 3,651 -- ------------ ------------ ------------ Net earnings (loss) applicable to common shareholders $ 720,607 (157,795) (235,885) ============ ============ ============ Net earnings (loss) per average common share outstanding: Before extraordinary loss: Basic $ 5.66 (1.64) (3.32) ============ ============ ============ Diluted $ 5.50 (1.64) (3.32) ============ ============ ============ After extraordinary loss: Basic $ 5.66 (1.68) (3.32) ============ ============ ============ Diluted $ 5.50 (1.68) (3.32) ============ ============ ============ Weighted average common shares outstanding: Basic 127,421 93,653 70,948 ============ ============ ============ Diluted 131,730 99,313 76,932 ============ ============ ============

See accompanying notes to consolidated financial statements. 34 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)

ACCUMU- RETAINED LATED UNAMOR- EARNINGS OTHER TIZED TOTAL PREFER- ADDITIONAL (ACCUMU- COMPRE- RESTRICTED STOCK- RED COMMON PAID-IN LATED HENSIVE STOCK TREASURY HOLDERS' STOCK STOCK CAPITAL DEFICIT) LOSS AWARDS STOCK EQUITY --------- ------ ---------- -------- ------- ---------- -------- ---------- Balance as of December 31, 1997 $ -- 7,077 1,521,128 (493,246) (27,113) (700) (600) 1,006,546 Comprehensive loss: Net loss -- -- -- (235,885) -- -- -- (235,885) 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 (244,734) Stock issued -- 13 2,816 (600) -- (2,600) 5,400 5,029 Stock repurchased -- -- -- -- -- -- (11,600) (11,600) Dividends on common stock -- -- -- (7,278) -- -- -- (7,278) Amortization of restricted stock awards -- -- -- -- -- 1,800 -- 1,800 --------- ------ ---------- -------- ------- ---------- -------- ---------- Balance as of December 31, 1998 -- 7,090 1,523,944 (737,009) (35,962) (1,500) (6,800) 749,763 Comprehensive loss: Net loss -- -- -- (154,144) -- -- -- (154,144) 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 -- -- -- -- (36,556) -- -- (36,556) ---------- Other comprehensive loss -- -- -- -- -- -- -- (29,280) ---------- Comprehensive loss (183,424) Stock issued 1,500 5,542 1,966,930 (1,100) -- (100) 7,600 1,980,372 Stock repurchased -- -- -- -- -- -- (11,600) (11,600) 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) Amortization of restricted stock awards -- -- -- -- -- 1,600 -- 1,600 --------- ------ ---------- -------- ------- ---------- -------- ---------- Balance as of December 31, 1999 1,500 12,632 3,491,828 (908,598) (65,242) -- (10,800) 2,521,320 Comprehensive income: Net income -- -- -- 730,342 -- -- -- 730,342 Other comprehensive loss, net of tax: Foreign currency translation adjustments -- -- -- -- (10,213) -- -- (10,213) Minimum pension liability adjustment -- -- -- -- 822 -- -- 822 Unrealized losses on marketable securities -- -- -- -- (10,764) -- -- (10,764) ---------- Other comprehensive loss -- -- -- -- -- -- -- (20,155) ---------- Comprehensive income: 710,187 Stock issued -- 232 69,163 (4,497) -- -- 21,499 86,397 Stock repurchased -- -- -- -- -- (10,699) (10,699) Tax benefit related to employee stock options -- -- 3,003 -- -- -- -- 3,003 Dividends on common stock -- -- -- (22,220) -- -- -- (22,220) Dividends on preferred stock -- -- -- (9,735) -- -- -- (9,735) Grant of restricted stock awards -- -- -- -- -- (5,217) -- (5,217) Forfeiture of restricted stock awards -- -- -- -- -- 129 -- 129 Amortization of restricted stock awards -- -- -- -- -- 4,439 -- 4,439 --------- ------ ---------- -------- ------- ---------- -------- ---------- Balance as of December 31, 2000 $ 1,500 12,864 3,563,994 (214,708) (85,397) (649) -- 3,277,604 ========= ====== ========== ======== ======= ========== ======== ==========

See accompanying notes to consolidated financial statements. 35 DEVON ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)

YEAR ENDED DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net earnings (loss) $ 730,342 (154,144) (235,885) Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: Depreciation, depletion and amortization of property and equipment 693,340 406,375 243,144 Amortization of goodwill 41,332 16,111 -- Accretion of interest on zero-coupon convertible senior debentures 6,950 -- -- Amortization of (premiums) discounts on other long-term debt, net (3,781) (728) 100 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt 2,408 (13,154) 16,104 Reduction of carrying value of oil and gas properties -- 476,100 422,500 (Gain) loss on sale of assets (683) 4,778 (264) Deferred income tax expense (benefit) 280,845 (72,490) (122,394) Other 3,849 2,100 4,801 Changes in assets and liabilities, net of effects of acquisitions of businesses: (Increase) decrease in: Accounts receivable (283,787) (92,416) 30,760 Inventories (8,322) (8,514) (1,427) Prepaid expenses 5,825 (4,418) (7,751) Other assets 3,812 (36,673) 17,230 Increase (decrease) in: Accounts payable 98,912 (22,495) (19,439) Income taxes payable 60,548 (19,318) (10,426) Accrued expenses 3,104 (38,387) 1,000 Deferred revenue 7,954 90,700 (100) Long-term other liabilities (23,616) (1,099) (3,482) ------------ ------------ ------------ Net cash provided by operating activities 1,619,032 532,328 334,471 ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Proceeds from sale of property and equipment 101,531 114,384 64,997 Proceeds from sale of investments 12,781 -- 42,584 Capital expenditures (1,280,132) (883,420) (712,812) (Increase) decrease in other assets (7,581) 719 (2,029) ------------ ------------ ------------ Net cash used in investing activities (1,173,401) (768,317) (607,260) ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings of long-term debt, net of issuance costs 2,580,086 1,944,417 1,506,220 Principal payments on long-term debt (2,951,711) (2,089,109) (1,242,013) Issuance of common stock, net of issuance costs 51,550 530,232 4,429 Retirement of preferred securities of subsidiary trust -- (50) -- Repurchase of common stock (10,699) (11,600) (11,600) Issuance of treasury stock 24,937 6,200 -- Dividends paid on common stock (22,220) (12,694) (7,278) Dividends paid on preferred stock (9,735) (3,651) -- (Decrease) increase in long-term other liabilities (51,779) 13,453 6,760 ------------ ------------ ------------ Net cash (used in) provided by financing activities (389,571) 377,198 256,518 ------------ ------------ ------------ Effect of exchange rate changes on cash (1,177) 704 (140) ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents 54,883 141,913 (16,411) Cash and cash equivalents at beginning of year 173,167 31,254 47,665 ------------ ------------ ------------ Cash and cash equivalents at end of year $ 228,050 173,167 31,254 ============ ============ ============

See accompanying notes to consolidated financial statements. 36 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Accounting policies used by Devon Energy Corporation and subsidiaries ("Devon") reflect industry practices and conform to accounting principles generally accepted in the United States of America. The more significant of such policies are briefly discussed below. 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 managed in three divisions: - the Gulf Division, which includes properties located primarily in the onshore South Texas and South Louisiana areas and offshore in the Gulf of Mexico; - the Rocky Mountain Division, which includes properties located in the Rocky Mountains area of the United States stretching from the Canadian Border into northern New Mexico; and - the Permian/Mid-Continent Division, which includes all domestic properties other than those included in the Gulf Division and the Rocky Mountain Division. 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 Argentina, Azerbaijan, Indonesia and Gabon. 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 accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. 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. 37 Property and Equipment Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by Devon for its own account, and which are not related to production, general corporate overhead or similar activities are also capitalized. For the years 2000, 1999 and 1998, such internal costs capitalized totaled $61.8 million, $28.9 million and $14.8 million, respectively. Unproved properties are excluded from amortized capitalized costs until it is determined whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for impairment annually. 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 six thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using the capitalized costs plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, and the estimated dismantlement and abandonment costs, net of estimated salvage values. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves. All costs related to production activities, including workover costs incurred solely to maintain or increase levels of production from an existing completion interval, are charged to expense as incurred. Depreciation 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 loss and reported as a separate component of stockholders' equity. Devon's investments in other short-term securities are also classified as "available for sale." 38 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 goodwill amortization was $57.4 million and $16.1 million at December 31, 2000 and 1999, respectively. Revenue Recognition and Gas Balancing Oil and gas revenues are recognized when sold. 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 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 financial instruments and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on 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 39 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. Devon adopted the provisions of SFAS 133, as amended, in the first quarter of the year ending December 31, 2001. In accordance with the transition provisions of SFAS 133, Devon recorded a net-of-tax cumulative-effect-type adjustment of $36.6 million in accumulated other comprehensive loss to recognize at fair value all derivatives that are designated as cash-flow hedging financial instruments. Additionally, Devon recorded a net-of-tax cumulative-effect-type adjustment to net earnings for a $49.5 million gain related to the fair value of financial instruments that do not qualify as hedges. This gain included $46.2 million related to the option embedded in Devon's debentures that are exchangeable into shares of Chevron Corporation common stock. 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 2000, Enron Capital and Trade Resource Corporation accounted for 20% of Devon's combined oil, gas and natural gas liquids sales. In 1998, Aquila Energy Marketing Corporation accounted for 11% of Devon's combined oil, gas and natural gas liquids sales. No purchaser accounted for over 10% of such revenues in 1999. 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. 40 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) and if Devon's zero coupon convertible senior debentures were converted to common stock. The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted earnings per share for 2000. The diluted loss per share calculations for 1999 and 1998 produce results that are anti-dilutive. (The diluted calculation for 1999 reduced the net loss by $4.3 million and increased the common shares outstanding by 5.7 million shares. The diluted calculation for 1998 reduced the net loss by $6.0 million and increased the common shares outstanding by 6.0 million shares.) Therefore, the diluted loss per share amounts for 1999 and 1998 reported in the accompanying consolidated statements of operations are the same as the basic loss per share amounts.

NET EARNINGS WEIGHTED APPLICABLE AVERAGE NET TO COMMON COMMON SHARES EARNINGS STOCKHOLDERS OUTSTANDING PER SHARE ------------ ------------- --------- (IN THOUSANDS) YEAR ENDED DECEMBER 31, 2000: Basic earnings per share $720,607 127,421 $5.66 Dilutive effect of: Potential common shares issuable upon conversion of senior convertible debentures (the increase in net earnings is net of income tax expense of $2,755,000) 4,309 2,248 Potential common shares issuable upon the exercise of outstanding stock options -- 2,061 ---------- -------- Diluted earnings per share $ 724,916 131,730 $5.50 ========== ======== =====

Options to purchase approximately 1.0 million shares of Devon's common stock with exercise prices ranging from $55.54 per share to $89.66 per share (with a weighted average price of $66.64 per share) were outstanding at December 31, 2000, but were not included in the computation of diluted earnings per share for 2000 because the options' exercise price exceeded the average market price of Devon's common stock during the year. The excluded options for 2000 expire between February 12, 2001 and June 1, 2010. All options were excluded from the diluted earnings per share calculations for 1999 and 1998. 41 Comprehensive Loss 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, 2000, 1999 and 1998, and changes during each of the years then ended, is presented in the following table.

FOREIGN MINIMUM UNREALIZED CURRENCY PENSION LOSSES ON TRANSLATION LIABILITY MARKETABLE ADJUSTMENTS ADJUSTMENTS SECURITIES TOTAL ----------- ----------- ---------- -------- (IN THOUSANDS) 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) (59,959) (52,836) Deferred taxes -- 153 23,403 23,556 -------- -------- -------- -------- 1999 activity, net of deferred taxes 7,517 (241) (36,556) (29,280) -------- -------- -------- -------- Balance as of December 31, 1999 (27,726) (960) (36,556) (65,242) 2000 activity (10,213) 1,346 (17,608) (26,475) Deferred taxes -- (524) 6,844 6,320 -------- -------- -------- -------- 2000 activity, net of deferred taxes (10,213) 822 (10,764) (20,155) -------- -------- -------- -------- Balance as of December 31, 2000 $(37,939) (138) (47,320) (85,397) ======== ======== ======== ========

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 2000, 1999 and 1998 at a per share rate of $0.05 per quarter. As adjusted for the pooling-of-interests method of accounting followed for the Santa Fe Snyder merger and the Northstar combination, annual dividends per share for 2000, 1999 and 1998 were $0.17, $0.14 and $0.10, 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. 42 Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized in accordance with accounting principles generally accepted in the United States of America. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Reference is made to Note 13 for a discussion of amounts recorded for these liabilities. Reclassification Certain of the 1999 and 1998 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2000 presentation. 2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION Santa Fe Snyder Merger Devon closed its merger with Santa Fe Snyder Corporation ("Santa Fe Snyder") on August 29, 2000. The merger was accounted for using the pooling-of-interests method of accounting for business combinations. Accordingly, all operational and financial information contained herein includes the combined amounts for Devon and Santa Fe Snyder for all periods presented. Devon issued approximately 40.6 million shares of its common stock to the former stockholders of Santa Fe Snyder based on an exchange ratio of 0.22 shares of Devon common stock for each share of Santa Fe Snyder common stock. Because the merger was accounted for using the pooling-of-interests method, all combined share information has been retroactively restated to reflect the exchange ratio. During 2000, Devon recorded a pre-tax charge of $60.4 million ($37.2 million net of tax) for direct costs related to the Santa Fe Snyder merger. 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 43 price and the allocation to assets and liabilities as of August 17, 1999, are shown below. Devon has sold certain of the assets acquired. Generally, the proceeds from such sales reduced the carrying value of oil and gas properties.

(IN THOUSANDS, EXCEPT SHARE PRICE) ------------------- Calculation and 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, $346.9 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 $346.9 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.) 44 Snyder Merger Santa Fe Snyder was formed on May 5, 1999, when the former Santa Fe Energy Resources, Inc. ("Santa Fe") closed its merger with Snyder Oil Corporation ("Snyder"). Because Devon's merger with Santa Fe Snyder was accounted for using the pooling-of-interests method, the accompanying consolidated financial statements are presented as though Devon merged with Snyder in May 1999. The Snyder 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 Snyder's operations since May 5, 1999. As restated for the Devon-Santa Fe Snyder pooling, each share of Snyder common stock was exchanged for 0.451 shares of Devon common stock. This resulted in the issuance of approximately 15.1 million shares of Devon stock in the Snyder merger. In addition, the Snyder merger also included the assumption of approximately $219 million of Snyder's long-term debt as of May 5, 1999. The calculation of the total purchase price and the allocation to assets and liabilities as of May 5, 1999, are as follows.

(IN THOUSANDS, EXCEPT SHARE PRICE) ------------------- Calculation and allocation of purchase price: Shares of Santa Fe common stock issued to Snyder stockholders, as adjusted for the Devon-Santa Fe Snyder pooling 15,130 Average Santa Fe stock price, as adjusted for the Devon-Santa Fe Snyder pooling $ 27.24 ------------ Fair value of common stock issued $ 412,092 Plus estimated merger costs incurred 1,485 ------------ Total purchase price 413,577 Plus fair value of liabilities assumed: Current liabilities 55,118 Long-term debt 219,001 Other long-term liabilities 26,254 ------------ 713,950 Less fair value of non oil and gas assets acquired: Current assets 16,755 Other assets 37,211 ------------ Fair value allocated to oil and gas properties, including $14.7 million of undeveloped leasehold $ 659,984 ============

Additionally, $135.4 million was added to oil and gas properties for deferred taxes created as a result of the Snyder merger. Due to the tax-free nature of the merger, Santa Fe's tax basis in the assets acquired and liabilities assumed were the same as Snyder's tax basis. The $135.4 million of deferred taxes recorded represent the deferred tax effect of the differences between the fair values assigned by Santa Fe for financial reporting purposes to the former Snyder assets and liabilities and their bases for income tax purposes. 45 Estimated proved reserves added in the Snyder merger were 17.7 million barrels of oil and natural gas liquids and 424 billion cubic feet of natural gas. Also added in the Snyder merger were approximately 800,000 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 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 (Unaudited) 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, the Snyder 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 does not include 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 following should be considered in connection with the pro forma financial information presented: o Expected annual cost savings of $30 to $35 million related to the Santa Fe Snyder merger and $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, Santa Fe Snyder and PennzEnergy and the elimination of duplicate staff and expenses. Some of the cost savings related to the Santa Fe Snyder merger involve items that, under the full cost method of accounting, are capitalized rather than expensed in the consolidated financial statements. Therefore, not all of the 46 $30 to $35 million of expected savings will result in reductions to expenses as reported in the accompanying consolidated statements of operations. 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 financial information also includes the related $207.0 million after-tax extraordinary loss resulting from the early extinguishment of debt. o The 1999 pro forma financial information includes a $4.2 million extraordinary loss recorded by Santa Fe Snyder. This loss related to the early extinguishment of debt. 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 1999 and 1998 pro forma results include reductions of the carrying value of oil and gas properties of $476.1 million and $422.5 million, respectively. The after-tax effect of these reductions, which were due to the full cost ceiling limitation, were $309.7 million in 1999 and $280.8 million in 1998. 47

PRO FORMA INFORMATION YEAR ENDED DECEMBER 31, ------------------------------ 1999 1998 ------------ ------------ (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) REVENUES Oil sales $ 702,477 487,218 Gas sales 806,337 802,785 Natural gas liquids sales 93,829 71,726 Other 87,453 306,103 ------------ ------------ Total revenues 1,690,096 1,667,832 ------------ ------------ COSTS AND EXPENSES Lease operating expenses 409,555 444,617 Production taxes 53,506 44,548 Depreciation, depletion and amortization of property and equipment 665,865 723,908 Amortization of goodwill 46,321 52,637 General and administrative expenses 147,028 177,678 Expenses related to prior mergers 16,800 13,149 Interest expense 196,990 206,421 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 476,100 422,500 ------------ ------------ Total costs and expenses 2,005,895 2,111,279 ------------ ------------ Earnings (loss) before income tax expense (benefit) and (315,799) (443,447) extraordinary item INCOME TAX EXPENSE (BENEFIT) Current 23,261 (1,076) Deferred (107,680) (121,131) ------------ ------------ Total income tax expense (benefit) (84,419) (122,207) ------------ ------------ Loss before extraordinary item (231,380) (321,240) Extraordinary loss (4,200) (206,963) ------------ ------------ Net loss (235,580) (528,203) Preferred stock dividends 9,736 5,625 ------------ ------------ Net loss applicable to common stockholders $ (245,316) (533,828) ============ ============ Net loss before extraordinary item per average common share outstanding - basic and diluted $ (2.20) (3.04) ============ ============ Net loss per average common share outstanding - basic and diluted $ (2.24) (4.97) ============ ============ Weighted average common shares outstanding - basic 109,656 107,371 ============ ============

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 48 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, 2000, approximately 13.1 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. 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 a 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 2000, 1999 and 1998, the San Juan Basin Transaction added approximately $12.3 million, $7.6 million and $8.4 million, respectively, to Devon's gas revenues. Under the terms of the San Juan Basin Transaction, Devon had a repurchase option which it could exercise at anytime. Devon exercised the repurchase option effective September 30, 2000. Devon had previously recorded 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 also received cash payments in exchange for agreeing not to exercise its repurchase option for specific periods of time prior to 2000. These payments were also 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 and $6.8 million in 1999 and 1998, respectively, which were added to the repurchase liability. The actual repurchase price as of September 30, 2000, was approximately $36.3 million. 4. SUPPLEMENTAL CASH FLOW INFORMATION Cash payments for interest in 2000, 1999 and 1998 were approximately $155.1 million, $115.6 million and $45.6 million, respectively. Cash payments for federal, state and foreign income taxes in 2000, 1999 and 1998 were approximately $81.8 million, $15.8 million and $19.4 million, respectively. 49 The 1999 PennzEnergy merger and Snyder merger involved non-cash consideration as presented below:

1999 -------------- (IN THOUSANDS) Value of common stock issued $ 1,130,269 Value of preferred stock issued 150,000 Employee stock options assumed 18,295 Liabilities assumed 2,259,174 Deferred tax liability created 474,306 ------------ Fair value of assets acquired with non-cash consideration $ 4,032,044 =============

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, ------------------------------------------------ 2000 1999 1998 ------------ ------------ ------------ (IN THOUSANDS) Oil, gas and natural gas liquids revenue accruals $ 438,304 218,462 74,660 Joint interest billings 122,778 66,658 33,136 Other 41,013 34,585 31,262 ------------ ------------ ------------ 602,095 319,705 139,058 Allowance for doubtful accounts (3,847) (3,700) (2,000) ------------ ------------ ------------ Net accounts receivable $ 598,248 316,005 137,058 ============ ============ ============

50 6. PROPERTY AND EQUIPMENT Property and equipment included the following:

DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ------------ ------------ ------------ (IN THOUSANDS) Oil and gas properties: Subject to amortization $ 9,169,593 8,125,886 4,584,676 Not subject to amortization: Acquired in 2000 74,164 -- -- Acquired in 1999 122,431 134,966 -- Acquired in 1998 44,833 56,922 65,702 Acquired prior to 1998 73,832 109,297 147,875 Accumulated depreciation, depletion and amortization (4,752,670) (4,129,824) (3,204,775) ------------ ------------ ------------ Net oil and gas properties 4,732,183 4,297,247 1,593,478 ------------ ------------ ------------ Other property and equipment 224,499 164,939 55,958 Accumulated depreciation and amortization (47,146) (38,766) (25,908) ------------ ------------ ------------ Net other property and equipment 177,353 126,173 30,050 ------------ ------------ ------------ Property and equipment, net of accumulated depreciation, depletion and amortization $ 4,909,536 4,423,420 1,623,528 ============ ============ ============

The costs not subject to amortization relate to unproved properties, none of which are individually significant. Subject to industry conditions, evaluation of these properties is expected to be completed within five years. Depreciation, depletion and amortization of property and equipment consisted of the following components:

YEAR ENDED DECEMBER 31, --------------------------------------------- 2000 1999 1998 ------------ ------------ ------------ (IN THOUSANDS) Depreciation, depletion and amortization of oil and gas properties $ 662,890 390,117 230,419 Depreciation and amortization of other property and equipment 22,974 13,660 12,564 Amortization of other assets 7,476 2,598 161 ------------ ------------ ------------ Total expense $ 693,340 406,375 243,144 ============ ============ ============

51 7. LONG-TERM DEBT AND RELATED EXPENSES A summary of Devon's long-term debt is as follows:

DECEMBER 31, ------------------------------------------------ 2000 1999 1998 ------------ ------------ ------------ (IN THOUSANDS) Borrowings under credit facilities with banks $ 146,652 645,141 411,271 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 -- Zero coupon convertible senior debentures exchangeable into shares of Devon Energy Corp. common stock, 3.875% due June 27, 2020 359,689 -- -- Other debentures: 10.25% due November 1, 2005 250,000 250,000 -- 10.125% due November 15, 2009 200,000 200,000 -- 11.00% due May 15, 2004 -- -- 100,000 Premium (discount) on debentures 33,375 37,467 (400) Senior notes: 8.05% due June 15, 2004 124,881 125,000 -- 6.76% due July 19, 2005 -- 75,000 75,000 8.75% due June 15, 2007 175,000 175,000 -- 6.79% due March 2, 2009 -- 150,000 150,000 Discount on notes (1,074) (1,400) -- ------------ ------------ ------------ 2,048,836 2,416,521 735,871 Less amount classified as current -- -- -- ------------ ------------ ------------ Long-term debt $ 2,048,836 2,416,521 735,871 ============ ============ ============

Maturities of long-term debt as of December 31, 2000, excluding the $32.3 million of premiums net of discounts, are as follows (in thousands): 2001 $ -- 2002 7,333 2003 7,333 2004 132,213 2005 257,332 2006 and thereafter 1,612,324 ------------- Total $ 2,016,535 ============= 52 Credit Facilities with Banks Concurrent with the closing of the Santa Fe Snyder merger on August 29, 2000, Devon entered into new unsecured long-term credit facilities aggregating $1 billion (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced the prior separate facilities of Devon and Santa Fe Snyder. Prior to the August 2000 merger, Devon and Santa Fe Snyder each had their own unsecured credit facilities. Devon's credit facilities prior to the merger aggregated $750 million, with $475 million in a U.S. facility and $275 million in a Canadian facility. Santa Fe Snyder's credit facilities prior to the merger aggregated $600 million. The $725 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $525 million. The Tranche B facility can be increased to as high as $625 million and reduced to as low as $425 million by reallocating the amount available between the Tranche B facility and the Canadian Facility. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until August 28, 2001 (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. Devon may borrow funds under the $275 million Canadian Facility until August 28, 2001 (the "Canadian Facility Revolving Period"). As disclosed in the prior paragraph, the Canadian Facility can be increased to as high as $375 million and reduced to as low as $175 million by reallocating the amount available between the Tranche B facility and the Canadian Facility. 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. 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, and are tied to margins determined by Devon's corporate credit ratings. 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 weighted average interest rate on the $146.7 million outstanding under the Credit Facilities at December 31, 2000, was 6.07%. The average interest rate on bank debt outstanding under the previous facilities at December 31, 1999 and 1998 was 6.85% and 6.28%, respectively. The agreements governing the Credit Facilities contain certain covenants and restrictions, including a maximum debt-to-capitalization ratio. At December 31, 2000, Devon was in compliance with such covenants and restrictions. 53 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 and mature August 15, 2008. The exchangeable debentures are callable beginning August 15, 2000, initially at 104.0% of principal and at prices declining to 100.5% of principal on or after August 15, 2007. The exchangeable 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, 2000, 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 In connection with the Snyder merger, Devon assumed Snyder's $175 million of 8.75% notes due in 2007. The notes are redeemable by Devon on or after June 15, 2002, initially at 104.375% of principal and at prices declining to 100% of principal on or after June 15, 2005. The notes are general unsecured obligations of Devon. In June 1999, Devon issued $125.0 million of 8.05% notes due 2004. The notes were issued for 98.758% of face value and Devon received total proceeds of $121.6 million after deducting related costs and expenses of $1.9 million. The notes, which mature June 15, 2004, are redeemable, upon not less than thirty nor more than sixty days notice, as a whole or in part, at the option of Devon at a redemption price equal to the sum of (i) 100% of the principal amount thereof, (ii) the applicable make-whole premium as determined by an independent investment banker and (iii) accrued and unpaid 54 interest. The notes are general unsecured obligations of Devon. The indentures for these notes include covenants that restrict the ability of Devon SFS Operating, Inc., a wholly-owned subsidiary of Devon, to take certain actions, including the ability to incur additional indebtedness and to pay dividends or repurchase capital stock. In September 2000, Devon, as required under the $125 million senior note agreement due to a "change of control", made a tender offer to repurchase the senior notes at a premium of 101.000%. As a result of this tender offer, $119,000 of senior notes were redeemed at a total cost to Devon of approximately $120,000. Zero Coupon Convertible Debentures In June 2000, Devon privately sold zero coupon convertible senior debentures. The debentures were sold at a price of $464.13 per debenture with a yield to maturity of 3.875% per annum. Each of the 760,000 debentures is convertible into 5.7593 shares of Devon common stock. Devon may call the debentures at any time after five years, and a debenture holder has the right to require Devon to repurchase the debentures after five, 10 and 15 years, at the issue price plus accrued original issue discount and interest. Devon's proceeds were approximately $346.1 million, net of debt issuance costs of approximately $6.6 million. Devon used the proceeds from the sale of these debentures to pay down other domestic long-term debt. Interest Expense Following are the components of interest expense for the years 2000, 1999 and 1998:

YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 1999 1998 ---------- ---------- ---------- (IN THOUSANDS) Interest based on debt outstanding $ 157,028 108,064 43,114 Amortization of debt premium, net (3,781) (1,328) -- Facility and agency fees 2,696 1,930 932 Amortization of capitalized loan costs 1,467 1,583 556 Capitalized interest (3,239) (1,925) (1,100) Other 158 1,289 30 ---------- ---------- ---------- Total interest expense $ 154,329 109,613 43,532 ========== ========== ==========

55 Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt Until mid-January 2000, the 6.76 % and 6.79% 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 declined in 2000 and 1998 and increased in 1999. Therefore, $2.4 million of increased expense was recorded in 2000, $13.2 million of reduced expense was recorded in 1999, and $16.1 million of increased expense was recorded in 1998. 8. INCOME TAXES At December 31, 2000, 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 $ 344,038 Net operating loss - various states 2002 - 2014 $ 37,357 Net operating loss - Canada 2001 - 2007 $ 2,180 Minimum tax credits Indefinite $ 84,991

All of the carryforward amounts shown above have been utilized for financial purposes to reduce deferred taxes. 56 The earnings (loss) before income taxes and the components of income tax expense (benefit) for the years 2000, 1999 and 1998 were as follows:

YEAR ENDED DECEMBER 31, ----------------------------------------- 2000 1999 1998 ---------- ---------- ---------- (IN THOUSANDS) Earnings (loss) before income taxes: U.S $ 872,455 (313,101) (274,150) Canada 156,085 57,402 19,958 International 113,440 56,321 (107,800) ---------- ---------- ---------- Total $1,141,980 (199,378) (361,992) ========== ========== ========== Current income tax expense (benefit): U.S. federal $ 106,742 12,544 (6,399) Various states 6,015 2,804 (1,189) Canada 2,268 2,908 1,975 Other 15,768 4,800 1,900 ---------- ---------- ---------- Total current tax expense (benefit) 130,793 23,056 (3,713) ---------- ---------- ---------- Deferred income tax expense (benefit): U.S. federal 151,832 (119,286) (88,824) Various states 33,399 (495) (4,836) Canada 67,318 26,654 11,166 Other 28,296 20,637 (39,900) ---------- ---------- ---------- Total deferred tax expense (benefit) 280,845 (72,490) (122,394) ---------- ---------- ---------- Total income tax expense (benefit) $ 411,638 (49,434) (126,107) ========== ========== ==========

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, ---------------------------------------- 2000 1999 1998 ---------- ---------- ---------- U.S. statutory tax (benefit) rate 35% (35)% (35)% Benefit from disposition of certain foreign assets (11) -- -- Non-deductible expenses 3 3 3 Nonconventional fuel source credits (2) (3) (1) State income taxes 2 1 (1) Taxation on foreign operations 5 7 2 Other 4 2 (3) ---------- ---------- ---------- Effective income tax (benefit) rate 36% (25)% (35)% ========== ========== ==========

57 The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 2000, 1999 and 1998 are presented below:

DECEMBER 31, ------------------------------------------ 2000 1999 1998 ---------- ---------- ---------- (IN THOUSANDS) Deferred tax assets: Net operating loss carryforwards $ 122,843 207,322 48,418 Minimum tax credit carryforwards 84,991 88,447 16,900 Production payments -- 21,527 19,105 Long-term debt 17,176 17,583 -- Other 95,283 50,618 20,388 ---------- ---------- ---------- Total gross deferred tax assets 320,293 385,497 104,811 Less valuation allowance 100 100 100 ---------- ---------- ---------- Net deferred tax assets 320,193 385,397 104,711 ---------- ---------- ---------- Deferred tax liabilities: Property and equipment, principally due to differences in depreciation, and the expensing of intangible drilling costs for tax purposes (687,473) (500,156) (49,256) Chevron Corporation common stock (166,596) (172,631) -- Other (83,971) (31,789) (469) ---------- ---------- ---------- Total deferred tax liabilities (938,040) (704,576) (49,725) ---------- ---------- ---------- Net deferred tax (liability) asset $ (617,847) (319,179) 54,986 ========== ========== ==========

As shown in the above table, Devon has recognized $320.2 million of net deferred tax assets as of December 31, 2000. Such amount consists primarily of $207.8 million of various carryforwards available to offset future income taxes. The carryforwards include federal net operating loss carryforwards, the majority of which do not begin to expire until 2008, state net operating loss carryforwards which expire primarily between 2002 and 2014, Canadian carryforwards which expire primarily between 2001 and 2007, 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 2001 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, 2000, related to depletion carryforwards acquired in a 1994 merger. 58 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 equated 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 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. 59 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 2000, 13.1 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 adoption of the share rights plan described later in this note. At December 31, 2000, 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, 2000, there were 109,000 and 487,540 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 number of shares to three million. On August 17, 1999, Devon's stockholders voted to increase the reserved number of shares to six million. On August 29, 2000, Devon's stockholders voted to increase the reserved number of shares to ten 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, 2000, there were 60 3,306,329 options outstanding under the 1997 Plan. There were 6,225,949 options available for future grants as of December 31, 2000. In addition to the stock options outstanding under the 1988 Plan, 1993 Plan and 1997 Plan, there were approximately 1,744,409, 1,630,123 and 78,553 stock options outstanding at the end of 2000 that were assumed as part of the Santa Fe Snyder merger, the PennzEnergy merger and the Northstar combination, respectively. Santa Fe Snyder, PennzEnergy and Northstar had granted these options prior to the Santa Fe Snyder merger, the PennzEnergy merger and the Northstar combination. As part of the Santa Fe Snyder merger, the PennzEnergy merger and the Northstar combination, the options were assumed by Devon and converted to Devon options at the exchange rate of 0.22, 0.4475 and 0.235 Devon options for each Santa Fe Snyder, PennzEnergy and Northstar option, respectively. A summary of the status of Devon's stock option plans as of December 31, 1998, 1999 and 2000, and changes during each of the years then ended, is presented below.

OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------ ---------------------------- WEIGHTED AVERAGE NUMBER EXERCISE NUMBER EXERCISE OUTSTANDING PRICE EXERCISABLE PRICE ----------- -------- ----------- -------- Balance at December 31, 1997 4,405,560 $ 31.564 2,744,115 $ 29.717 ========= ======== Options granted 1,652,789 $ 34.262 Options exercised (187,953) $ 23.943 Options forfeited (349,740) $ 35.326 ---------- Balance at December 31, 1998 5,520,656 $ 31.768 4,079,125 $ 30.479 ========= ======== Options granted 1,564,108 $ 31.736 Options assumed in the PennzEnergy merger 2,081,894 $ 55.643 Options assumed in the Snyder merger 979,220 $ 35.182 Options exercised (1,139,231) $ 28.509 Options forfeited (452,746) $ 36.369 ---------- Balance at December 31, 1999 8,553,901 $ 38.202 7,063,983 $ 39.547 ========= ======== Options granted 1,624,800 $ 51.430 Options exercised (2,488,756) $ 33.106 Options forfeited (333,991) $ 60.354 ---------- Balance at December 31, 2000 7,355,954 $ 41.843 6,024,796 $ 40.718 ========== ========= ========

The weighted average fair values of options granted during 2000, 1999 and 1998 were $28.73, $12.80 and $13.44, 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 2000, 1999 and 1998, respectively: risk-free interest rates of 5.5%, 6.0% and 5.0%; dividend yields of 0.4%, 0.5% and 0.4%; expected lives of 5, 5 and 5 years; and volatility of the price of the underlying common stock of 40.0%, 35.2% and 31.7%. 61 The following table summarizes information about Devon's stock options which were outstanding, and those which were exercisable, as of December 31, 2000:

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-$26.501 886,899 2.98 Years $ 22.732 881,065 $ 22.719 $28.830-$33.381 1,892,214 6.52 Years $ 30.691 1,612,472 $ 30.705 $34.375-$39.773 1,288,365 6.10 Years $ 36.550 1,263,100 $ 36.554 $40.125-$49.950 522,150 5.56 Years $ 46.067 506,884 $ 46.017 $50.142-$59.813 2,146,853 7.75 Years $ 53.072 1,155,202 $ 54.212 $60.150-$89.660 619,473 4.84 Years $ 71.797 606,073 $ 72.050 ---------- ---------- 7,355,954 6.17 Years $ 41.843 6,024,796 $ 40.718 ========== ==========

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 2000, 1999 and 1998 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, --------------------------------------------- 2000 1999 1998 --------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Net earnings (loss) available to common shareholders As reported $ 720,607 (157,795) (235,885) Pro forma $ 701,852 (173,005) (252,070) Net earnings (loss) per share available to common shareholders: As reported: Basic $ 5.66 (1.68) (3.32) Diluted $ 5.50 (1.68) (3.32) Pro forma: Basic $ 5.51 (1.85) (3.55) Diluted $ 5.36 (1.85) (3.55)

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 62 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, 2000, 1999 and 1998.

2000 1999 1998 --------------------------- -------------------------- ----------------------- CARRYING FAIR CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE ------------ ----------- ----------- ----------- -------- -------- (IN THOUSANDS) Investments $ 606,117 606,117 634,281 634,281 1,930 1,930 Oil and gas price hedge $ -- (57,560) -- (9,540) -- 1,988 agreements Foreign exchange hedge $ -- (533) -- (2,535) -- (9,310) agreements Long-term debt (including current portion) $ (2,048,836) (2,049,779) (2,416,521) (2,400,334) (735,871) (758,075) TCP Securities $ -- -- -- -- (149,500) (171,400)

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, 2000, 1999 and 1998. 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) an internal discounted cash flow calculation, (b) quotes obtained from the counterparty to the hedge agreement or (c) 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. 63 The following table covers Devon's notional volumes and pricing on open natural gas hedging instruments as of December 31, 2000:

YEAR OF PRODUCTION -------- -------- 2001 2002 -------- -------- Volumes (billion British thermal units) 14,027 3,333 Average price to be received $ 2.18 2.52

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 F.E.R.C.'s Gas Market Report" ("Inside FERC") for the Rocky Mountains. In addition to the above gas hedging instruments, Devon also had a natural gas basis swap in effect as of December 31, 2000. In this basis swap, which covers 20,000 MMBtus per day, Devon owes the counterparty the applicable monthly Colorado Interstate Gas Co. index price as published by Inside FERC, while the counterparty owes Devon the average NYMEX price for the last three settlement days of the month less $0.30 per MMBtu. The net difference is settled by the parties each month. This basis swap continues through August 31, 2004. 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, 2000, Devon had open foreign currency hedging instruments in which it will sell $10 million in 2001 at average Canadian-to-U.S. dollar exchange rates of $0.7102. Under this agreement, Devon will buy the same amount of dollars at the floating exchange rate. Devon's 1999 and 1998 consolidated balance sheets include deferred revenues of $0.4 million and $1.0 million, respectively, for gains realized on the early termination of commodity and foreign currency hedging instruments in prior years. 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. 64 In 2000, Devon established a defined benefit postretirement plan, which is unfunded, and covers substantially all current employees including former Santa Fe Snyder and PennzEnergy employees who remained with Devon. Additionally, Devon assumed responsibility for the PennzEnergy sponsored defined benefit postretirement plans, which are unfunded. 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. 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, 2000, 1999 and 1998.

PENSION BENEFITS OTHER RETIREMENT BENEFITS ------------------------------------- ------------------------------------- 2000 1999 1998 2000 1999 1998 --------- --------- --------- --------- --------- --------- (IN THOUSANDS) Change in benefit obligation: Benefit obligation at beginning of year $ 155,569 63,841 53,859 $ 37,860 8,100 6,600 Service cost 6,736 4,937 2,685 809 838 400 Interest cost 11,283 6,464 4,035 2,330 1,249 500 Participant contributions -- -- -- 147 -- 100 Amendments 4,303 -- 293 (1,985) -- -- Mergers and acquisitions -- 87,751 -- -- 28,659 -- Curtailment gain (3,037) -- -- (346) -- -- Actuarial (gain) loss (2,963) (3,525) 5,573 (3,153) 600 1,000 Benefits paid (7,290) (3,899) (2,604) (3,520) (1,586) (500) --------- --------- --------- --------- --------- --------- Benefit obligation at end of year 164,601 155,569 63,841 32,142 37,860 8,100 --------- --------- --------- --------- --------- --------- Change in plan assets: Fair value of plan assets at beginning of year 157,894 41,531 43,136 -- -- -- Actual return on plan assets 2,574 14,808 113 -- -- -- PennzEnergy merger -- 104,181 -- -- -- -- Employer contributions 1,664 1,273 886 3,373 1,486 400 Participant contributions -- -- -- 147 100 100 Benefits paid (7,290) (3,899) (2,604) (3,520) (1,586) (500) --------- --------- --------- --------- --------- --------- Fair value of plan assets at end of year 154,842 157,894 41,531 -- -- -- --------- --------- --------- --------- --------- --------- Funded status (9,759) 2,325 (22,310) (32,142) (37,860) (8,100) Unrecognized net actuarial (gain) loss 9,888 (2,723) 9,130 (2,199) 800 200 Unrecognized prior service cost 1,570 1,966 2,322 (1,201) -- -- Unrecognized net transition (asset) obligation (6,331) (400) (500) 1,152 2,100 2,300 Other -- 100 -- -- 100 100 --------- --------- --------- --------- --------- --------- Net amount recognized $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500) ========= ========= ========= ========= ========= ========= The net amounts recognized in the consolidated balance sheets consist of: (Accrued) prepaid benefit cost $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500) Additional minimum liability (735) (3,110) (2,987) -- -- -- Intangible asset 508 1,537 1,808 -- -- -- Accumulated other comprehensive loss 227 1,573 1,179 -- -- -- --------- --------- --------- --------- --------- --------- Net amount recognized $ (4,632) 1,268 (11,358) $ (34,390) (34,860) (5,500) ========= ========= ========= ========= ========= ========= Assumptions: Discount rate 7.65% 7.34% 6.69% 7.65% 7.32% 6.75% Expected return on plan assets 8.50% 8.37% 9.35% N/A N/A N/A Rate of compensation increase 5.00% 4.88% 4.84% 5.00% 4.75% 4.75%

The benefit obligation for the defined benefit pension plans with benefit obligations in excess of assets was $87.0 million as of December 31, 2000. The plan assets for these plans at December 31, 2000 totaled $49.9 million. 65 Net periodic benefit cost included the following components:

OTHER POSTRETIREMENT PENSION BENEFITS BENEFITS -------------------------------- ------------------------------- 2000 1999 1998 2000 1999 1998 -------- -------- -------- -------- -------- -------- (IN THOUSANDS) Service cost $ 6,736 4,937 2,685 $ 809 838 400 Interest cost 11,283 6,464 4,035 2,330 1,249 500 Expected return on plan assets (13,247) (6,900) (3,932) -- -- -- Amortization of prior service cost 289 256 256 (37) -- -- Amortization of transition obligation (52) -- -- 170 200 200 Recognized net actuarial (gain) loss 294 320 11 (207) -- -- -------- -------- -------- -------- -------- -------- Net periodic benefit cost $ 5,303 5,077 3,055 $ 3,065 2,287 1,100 ======== ======== ======== ======== ======== ========

For measurement purposes, a 10% 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 2005 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 2000 $ 230 $ (204) Effect on year-end 2000 postretirement benefit obligation $ 1,062 $ (1,009)

Devon has incurred certain postemployment benefits to former or inactive employees who are not retirees. These benefits include salary continuance, severance and disability health care and life insurance which are accounted for under SFAS No. 112, "Employer's Accounting for Postemployment Benefits." The accrued postemployment benefit liability was approximately $12.7 million and $2.5 million at the end of 2000 and 1999, respectively. Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a certain percentage of the employees' contributions to the plan. The matching percentage is determined annually by the Board of Directors. Devon's matching contributions to the plan were $5.0 million, $4.3 million and $2.3 million for the years ended December 31, 2000, 1999 and 1998, 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). 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. 66 During the years 2000, 1999 and 1998, Devon's combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $2.1 million, $1.9 million and $1.8 million, respectively. As a result of the Santa Fe Snyder merger, Devon also has a savings plan with respect to certain personnel employed in foreign locations. The plan is an unsecured creditor of Devon and at December 31, 2000, 1999 and 1998, Devon's liability with respect to the plan totaled $0.4 million, $0.4 million and $0.3 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, 2000, Devon's consolidated balance sheet included $7.8 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. 67 Royalty Matters More than 30 oil companies, including Devon, are involved in disputes in which it is alleged that such companies and related parties underpaid royalty, overriding royalty and working interests owners 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. To avoid expensive and protracted litigation, certain parties, including Devon, have entered into a global settlement agreement which provides for a settlement of all claims of all members of the settlement class. The court held a fairness hearing and issued an Amended Final Judgment approving the settlement on September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon's share of the proposed settlement, which was accrued at December 31, 2000, is not material to its financial position, results of operations or liquidity. Also, pending in federal court in Texas is a similar suit alleging underpaid royalties to the United States in connection with natural gas and natural gas liquids produced and sold from United States owned and/or controlled lands. The claims were filed by private litigants against Devon and numerous other producers, under the federal False Claims Act. The United States served notice of its intent to intervene as to certain defendants, but not Devon. Devon and certain other defendants are challenging the constitutionality of whether a claim under the federal False Claims Act can be maintained absent government intervention. Devon believes that it has acted reasonably and paid royalties in good faith. Devon does not currently believe that it is subject to material exposure in association with this litigation. As a result, Devon's monetary exposure in this suit is not expected to be material. Maersk Rig Contract In December 1997, the working interest owner partner of Pennzoil Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the PennzEnergy merger, entered into a contract 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 70/80 in Lake Maracaibo, Venezuela. The rig was assembled and delivered by Maersk 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. The contract, which expires October 1, 2001, provides for early termination, with a charge for such termination which is currently estimated at $42,000 per day with certain escalation factors for the balance of the term. As of December 31, 2000, Devon's consolidated balance sheet included accrued liabilities, reflected in "Other liabilities," for the expected cost to terminate/settle the contract. 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 the contract. 68 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, 2000:

YEAR ENDING DECEMBER 31, (IN THOUSANDS) ------------------------ 2001 $ 14,394 2002 12,279 2003 11,513 2004 10,779 2005 10,293 Thereafter 20,466 -------- Total minimum lease payments required $ 79,724 ========

Total rental expense for all operating leases is as follows for the years ended December 31:

(IN THOUSANDS) 2000 $ 18,564 1999 $ 24,204 1998 $ 18,319

Santa Fe Energy Trust The Santa Fe Energy Trust (the "Trust") was formed in 1992 to hold 6.3 million Depository Units, each consisting of beneficial ownership of one unit of undivided interest in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon U.S. Treasury obligation maturing on or about February 15, 2008, when the Trust will be liquidated. The assets of the Trust consist of certain oil and gas properties conveyed to it by Santa Fe Snyder. For any calendar quarter ending on or prior to December 31, 2002, the Trust will receive additional support payments to the extent that it needs such payments to distribute $0.39 per Depository Unit per quarter. The source of such support payments is limited to Devon's remaining royalty interest in certain of the properties conveyed to the Trust. The aggregate amount of the additional royalty payments (net of any amounts recouped) is limited to $19.4 million on a revolving basis. If such support payments are made, certain proceeds otherwise payable to the Trust in subsequent quarters may be reduced to recoup the amount of such support payments. Through the end of 2000, the Trust had received support payments totaling $4.2 million and Devon had recouped all such payments. Depending on various factors, such as sales volumes and prices and the level of operating costs and capital expenditures incurred, proceeds payable to the Trust with respect to operations in subsequent quarters may not be sufficient to make the required quarterly distributions. In such instances, Devon would be required to make support payments. 69 At December 31, 2000 and 1999, accounts payable as shown on the accompanying consolidated balance sheets included $4.1 million and $3.4 million, respectively, due to the Trust. 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. During 1999 and 1998, Devon reduced the carrying value of its oil and gas properties by $476.1 million and $422.5 million, respectively, due to the full cost ceiling limitations. The after-tax effect of these reductions in 1999 and 1998 were $309.7 million and $280.8 million, respectively. 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, ----------------------------------------- 2000 1999 1998 ---------- ---------- ----------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 291,355 3,002,269 245,467 Deferred income taxes -- 131,700 21,382 ---------- ---------- ----------- Total proved, including deferred income taxes $ 291,355 3,133,969 266,849 ========== ========== =========== Unproved, excluding deferred income taxes: Business combinations -- 83,505 5,278 Other acquisitions 55,344 40,583 55,827 Deferred income taxes -- -- 661 ---------- ---------- ------- Total unproved, including deferred income taxes $ 55,344 124,088 61,766 ========== ========== ======= Exploration costs $ 212,719 157,706 176,014 Development costs $ 636,379 336,126 294,105

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DOMESTIC ----------------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------------- 2000 1999 1998 ---------- ---------- ------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 177,072 2,670,237 87,549 Deferred income taxes -- 131,700 -- ---------- ---------- ------- Total proved, including deferred income taxes $ 177,072 2,801,937 87,549 ========== ========== ======= Unproved, excluding deferred income taxes: Business combinations -- 81,755 -- Other acquisitions 34,805 27,728 40,364 Deferred income taxes -- -- -- ---------- ---------- ------- Total unproved, including deferred income taxes $ 34,805 109,483 40,364 ========== ========== ======= Exploration costs $ 117,119 88,171 71,486 Development costs $ 466,090 228,095 149,286

CANADA -------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------- 2000 1999 1998 ------- --------- -------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $69,736 29,532 107,818 Deferred income taxes -- -- 21,382 ------- --------- -------- Total proved, including deferred income taxes $69,736 29,532 129,200 ======= ========= ======= Unproved, excluding deferred income taxes: Business combinations -- -- 5,278 Other acquisitions 16,977 9,155 10,263 Deferred income taxes -- -- 661 ------- --------- ---------- Total unproved, including deferred income taxes $16,977 9,155 16,202 ======= ========= ======== Exploration costs $54,769 37,197 49,928 Development costs $56,654 29,811 75,119

INTERNATIONAL ---------------------------------------- YEAR ENDED DECEMBER 31, ---------------------------------------- 2000 1999 1998 ---------- --------- ------- (IN THOUSANDS) Property acquisition costs: Proved, excluding deferred income taxes $ 44,547 302,500 50,100 Deferred income taxes -- -- -- ---------- --------- ------- Total proved, including deferred income taxes $ 44,547 302,500 50,100 ========== ========= ======= Unproved, excluding deferred income taxes: Business combinations -- 1,750 -- Other acquisitions 3,562 3,700 5,200 Deferred income taxes -- -- -- ---------- --------- ------- Total unproved, including deferred income taxes $ 3,562 5,450 5,200 ========== ========= ======= Exploration costs $ 40,831 32,338 54,600 Development costs $ 113,635 78,220 69,700

Pursuant to the full-cost method of accounting, Devon capitalizes certain of its general and administrative expenses which are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $61.8 million, $28.9 million and $14.8 million in the years 2000, 1999 and 1998, respectively. Due to the tax-free nature of the merger between Santa Fe and Snyder in May 1999, additional deferred tax liabilities of $131.7 million were allocated to proved properties. Due to the 71 tax-free nature of the PennzEnergy merger in August 1999, additional deferred tax liabilities of $346.9 million were recorded in 1999 and allocated to goodwill. 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.

TOTAL ----------------------------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 1998 --------------- --------------- --------------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 2,718,445 1,256,872 681,978 Production and operating expenses (597,333) (377,472) (274,618) Depreciation, depletion and amortization (662,890) (390,117) (230,419) Amortization of goodwill (41,332) (16,111) -- Reduction of carrying value of oil and gas -- (476,100) (422,500) properties Income tax (expense) benefit (571,755) (24,984) 65,515 --------------- --------------- --------------- Results of operations for oil and gas producing activities $ 845,135 (27,912) (180,044) =============== =============== =============== Depreciation, depletion and amortization per equivalent barrel of production $ 5.48 4.46 3.74 =============== =============== ===============

DOMESTIC ----------------------------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 1998 --------------- --------------- --------------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 2,167,571 891,670 417,313 Production and operating expenses (462,849) (254,077) (164,612) Depreciation, depletion and amortization (541,174) (293,841) (154,127) Amortization of goodwill (41,303) (16,106) -- Reduction of carrying value of oil and gas properties -- (463,700) (301,400) Income tax (expense) benefit (445,783) 37,786 63,630 --------------- --------------- --------------- Results of operations for oil and gas producing activities $ 676,462 (98,268) (139,196) =============== =============== =============== Depreciation, depletion and amortization per equivalent barrel of production $ 5.73 4.98 4.41 =============== =============== ===============

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CANADA ----------------------------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 1998 --------------- --------------- --------------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 303,537 204,501 169,965 Production and operating expenses (64,773) (62,595) (58,506) Depreciation, depletion and amortization (64,094) (64,514) (43,392) Reduction of carrying value of oil and gas properties -- -- -- Income tax (expense) benefit (79,363) (37,736) (37,615) --------------- --------------- --------------- Results of operations for oil and gas producing activities $ 95,307 39,656 30,452 =============== =============== =============== Depreciation, depletion and amortization per equivalent barrel of production $ 4.05 3.56 2.41 =============== =============== ===============

INTERNATIONAL ----------------------------------------------------- YEAR ENDED DECEMBER 31, ----------------------------------------------------- 2000 1999 1998 --------------- --------------- --------------- (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS) Oil, gas and natural gas liquids sales $ 247,337 160,701 94,700 Production and operating expenses (69,711) (60,800) (51,500) Depreciation, depletion and amortization (57,622) (31,762) (32,900) Amortization of goodwill (29) (5) -- Reduction of carrying value of oil and gas properties -- (12,400) (121,100) Income tax (expense) benefit (46,609) (25,034) 39,500 --------------- --------------- --------------- Results of operations for oil and gas producing activities $ 73,366 30,700 (71,300) =============== =============== =============== Depreciation, depletion and amortization per equivalent barrel of production $ 5.38 3.06 3.78 =============== =============== ===============

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." 73 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, 2000. Approximately 80%, 98% and 96%, of the respective year-end 2000, 1999 and 1998 domestic proved reserves were calculated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and Ryder-Scott Company Petroleum Consultants. The remaining percentages of domestic reserves are based on Devon's own estimates. All of the year-end 2000 and 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates. All of the year-end 1998 Canadian proved reserves were calculated by the independent petroleum consultants of Paddock Lindstrom & Associates and AMH Group Ltd. All of the international proved reserves other than Canada as of December 31, 2000 and 1999 were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants. Of the 1998 international reserves other than Canada, 87% were calculated by Ryder-Scott Company Petroleum Consultants and 13% were based on Devon's own estimates.

TOTAL ------------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ------------- ------------- ------------- Proved reserves as of December 31, 1997 218,741 1,403,204 24,478 Revisions of estimates (9,452) (53,209) 2,391 Extensions and discoveries 27,497 174,527 8,652 Purchase of reserves 30,283 164,429 518 Production (25,628) (198,051) (3,054) Sale of reserves (5,984) (13,906) (306) ------------- ------------- ------------- Proved reserves as of December 31, 1998 235,457 1,476,994 32,679 Revisions of estimates 12,367 6,888 3,254 Extensions and discoveries 12,809 406,157 4,342 Purchase of reserves 272,412 1,417,747 32,795 Production (31,756) (304,203) (5,111) Sale of reserves (4,572) (53,956) (142) ------------- ------------- ------------- Proved reserves as of December 31, 1999 496,717 2,949,627 67,817 Revisions of estimates (4,135) 99,223 3,312 Extensions and discoveries 33,939 601,317 6,041 Purchase of reserves 24,145 301,144 33 Production (42,561) (426,146) (7,400) Sale of reserves (48,861) (66,981) (8,046) ------------- ------------- ------------- Proved reserves as of December 31, 2000 459,244 3,458,184 61,757 ============= ============= ============= Proved developed reserves as of: December 31, 1997 187,758 1,204,874 21,832 December 31, 1998 179,746 1,282,447 19,381 December 31, 1999 301,149 2,500,985 52,102 December 31, 2000 261,432 2,631,267 46,256

74

DOMESTIC ------------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ------------- ------------- ------------- Proved reserves as of December 31, 1997 128,402 784,124 18,172 Revisions of estimates (19,849) 10,919 219 Extensions and discoveries 3,042 108,308 371 Purchase of reserves 1,813 58,655 -- Production (12,257) (121,419) (2,468) Sale of reserves -- (2,300) -- ------------- ------------- ------------- Proved reserves as of December 31, 1998 101,151 838,287 16,294 Revisions of estimates 23,986 35,751 3,407 Extensions and discoveries 1,890 230,059 2,794 Purchase of reserves 142,908 1,399,634 32,709 Production (17,822) (221,061) (4,396) Sale of reserves (2,689) (8,284) (4) ------------- ------------- ------------- Proved reserves as of December 31, 1999 249,424 2,274,386 50,804 Revisions of estimates (3,196) 100,844 4,296 Extensions and discoveries 20,430 504,977 5,092 Purchase of reserves 20,418 52,929 9 Production (28,562) (355,087) (6,702) Sale of reserves (32,977) (56,742) (7,981) ------------- ------------- ------------- Proved reserves as of December 31, 2000 225,537 2,521,307 45,518 ============= ============= ============= Proved developed reserves as of: December 31, 1997 115,559 646,882 16,789 December 31, 1998 92,931 663,864 14,777 December 31, 1999 214,267 1,959,531 48,237 December 31, 2000 192,190 2,087,287 42,155

75

CANADA ------------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ------------- ------------- ------------- 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 Revisions of estimates 2,872 (5,854) 343 Extensions and discoveries 2,787 64,566 571 Purchase of reserves 3,597 27,224 24 Production (4,760) (62,284) (682) Sale of reserves (136) (6,361) (65) ------------- ------------- ------------- Proved reserves as of December 31, 2000 36,492 523,509 4,204 ============= ============= ============= Proved developed reserves as of 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 December 31, 2000 29,721 507,703 4,072

76

INTERNATIONAL ------------------------------------------------- NATURAL GAS OIL GAS LIQUIDS (MBBLS) (MMCF) (MBBLS) ------------- ------------- ------------- Proved reserves as of December 31, 1997 54,200 36,300 1,200 Revisions of estimates 4,114 6,274 2,420 Extensions and discoveries 23,800 3,700 8,200 Purchase of reserves 20,300 -- -- Production (7,114) (9,474) (20) Sale of reserves -- -- -- ------------- ------------- ------------- Proved reserves as of December 31, 1998 95,300 36,800 11,800 Revisions of estimates (8,791) 12,181 115 Extensions and discoveries 10,700 123,400 1,100 Purchase of reserves 126,708 6,223 -- Production (8,756) (9,581) (15) Sale of reserves -- -- -- ------------- ------------- ------------- Proved reserves as of December 31, 1999 215,161 169,023 13,000 Revisions of estimates (3,811) 4,233 (1,327) Extensions and discoveries 10,722 31,774 378 Purchase of reserves 130 220,991 -- Production (9,239) (8,775) (16) Sale of reserves (15,748) (3,878) -- ------------- ------------- ------------- Proved reserves as of December 31, 2000 197,215 413,368 12,035 ============= ============= ============= Proved developed reserves as of December 31, 1997 37,000 35,700 -- December 31, 1998 53,600 35,000 100 December 31, 1999 57,614 40,078 -- December 31, 2000 39,521 36,277 29

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, ------------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- (IN THOUSANDS) Future cash inflows $ 40,594,130 18,494,929 5,114,485 Future costs: Development (1,634,888) (1,506,678) (495,977) Production (8,198,640) (6,270,893) (2,091,688) Future income tax expense (9,087,923) (1,928,398) (196,475) ------------- ------------- ------------- Future net cash flows 21,672,679 8,788,960 2,330,345 10% discount to reflect timing of cash flows (9,200,492) (4,020,526) (916,757) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 12,472,187 4,768,434 1,413,588 ============= ============= =============

77

DOMESTIC ------------------------------------------------- DECEMBER 31, ------------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- (IN THOUSANDS) Future cash inflows $ 29,143,762 11,362,918 2,718,030 Future costs: Development (915,969) (750,497) (162,715) Production (5,660,966) (3,894,271) (1,123,932) Future income tax expense (6,345,941) (1,071,699) (117,912) ------------- ------------- ------------- Future net cash flows 16,220,886 5,646,451 1,313,471 10% discount to reflect timing of cash flows (6,591,538) (2,335,312) (503,689) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 9,629,348 3,311,139 809,782 ============= ============= =============

CANADA ------------------------------------------------- DECEMBER 31, ------------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- (IN THOUSANDS) Future cash inflows $ 5,686,629 1,666,358 1,333,655 Future costs: Development (84,492) (66,631) (85,362) Production (616,605) (514,825) (491,256) Future income tax expense (1,967,441) (204,290) (39,563) ------------- ------------- ------------- Future net cash flows 3,018,091 880,612 717,474 10% discount to reflect timing of cash flows (1,240,934) (320,722) (279,568) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 1,777,157 559,890 437,906 ============= ============= =============

INTERNATIONAL ------------------------------------------------- DECEMBER 31, ------------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- (IN THOUSANDS) Future cash inflows $ 5,763,739 5,465,653 1,062,800 Future costs: Development (634,427) (689,550) (247,900) Production (1,921,069) (1,861,797) (476,500) Future income tax expense (652,409) (39,000) ------------- ------------- ------------- (774,541) Future net cash flows 2,433,702 2,261,897 299,400 10% discount to reflect timing of cash flows (1,368,020) (1,364,492) (133,500) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 1,065,682 897,405 165,900 ============= ============= =============

Future cash inflows are computed by applying year-end prices (averaging $23.77 per barrel of oil, adjusted for transportation and other charges, $8.04 per Mcf of gas and $29.80 per barrel of natural gas liquids at December 31, 2000) 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. Subsequent to December 31, 2000, the price of natural gas has declined. The average price in February 2001 for gas sold at market sensitive prices in North America was approximately one-third below the year-end 2000 price. 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. 78 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. 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, ------------------------------------------------- 2000 1999 1998 ------------- ------------- ------------- (IN THOUSANDS) Beginning balance $ 4,768,434 1,413,588 1,680,676 Sales of oil, gas and natural gas liquids, net of production costs (2,010,675) (879,400) (407,360) Net changes in prices and production costs 9,753,295 1,737,640 (743,193) Extensions, discoveries, and improved recovery, net of future development costs 2,742,182 315,932 280,414 Purchase of reserves, net of future development costs 618,134 2,881,881 223,055 Development costs incurred during the period which reduced future development costs 182,533 233,880 284,999 Revisions of quantity estimates 420,250 (62,821) (181,314) Sales of reserves in place (818,602) (77,707) (36,565) Accretion of discount 581,172 146,904 201,465 Net change in income taxes (4,221,575) (929,237) 305,317 Other, primarily changes in timing 457,039 (12,226) (193,906) ------------- ------------- ------------- Ending balance $ 12,472,187 4,768,434 1,413,588 ============= ============= =============

17. SEGMENT INFORMATION Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three reportable segments: its operations in the U.S., its operations in Canada, and its international operations outside of North America. Substantially all of these segments' operations involve oil and gas producing activities. Certain information regarding such activities for each segment is included in Notes 15 and 16. Following is certain financial information regarding Devon's segments for 2000, 1999 and 1998. The revenues reported are all from external customers. 79 17. SEGMENT INFORMATION (CONTINUED)

U.S. CANADA INTERNATIONAL TOTAL ------------- ------------- ------------- ------------- (IN THOUSANDS) AS OF DECEMBER 31, 2000: Current assets $ 644,685 79,372 210,080 934,137 Property and equipment, net of accumulated 3,639,673 585,517 684,346 4,909,536 depreciation, depletion and amortization Other assets 964,934 89 51,782 1,016,805 ------------- ------------- ------------- ------------- Total assets $ 5,249,292 664,978 946,208 6,860,478 ============= ============= ============= ============= Current liabilities 448,994 74,154 105,839 628,987 Long-term debt 1,902,184 146,652 -- 2,048,836 Deferred tax liabilities (assets) 536,935 68,578 21,313 626,826 Other liabilities 258,812 1,831 17,582 278,225 Stockholders' equity 2,102,367 373,763 801,474 3,277,604 ------------- ------------- ------------- ------------- Total liabilities and stockholders' equity $ 5,249,292 664,978 946,208 6,860,478 ============= ============= ============= ============= YEAR ENDED DECEMBER 31, 2000: REVENUES Oil sales $ 726,897 116,427 235,435 1,078,759 Gas sales 1,304,626 169,032 11,563 1,485,221 Natural gas liquids sales 136,048 18,078 339 154,465 Other 58,569 4,984 2,105 65,658 ------------- ------------- ------------- ------------- Total revenues 2,226,140 308,521 249,442 2,784,103 ------------- ------------- ------------- ------------- COSTS AND EXPENSES Lease operating expenses 319,154 52,340 69,286 440,780 Transportation costs 41,956 11,353 -- 53,309 Production taxes 101,739 1,080 425 103,244 Depreciation, depletion and amortization of property and equipment 565,633 64,735 62,972 693,340 Amortization of goodwill 41,303 -- 29 41,332 General and administrative expenses 80,358 10,380 2,270 93,008 Expenses related to mergers 60,373 -- -- 60,373 Interest expense 143,169 10,140 1,020 154,329 Deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt -- 2,408 -- 2,408 ------------- ------------- ------------- ------------- Total costs and expenses 1,353,685 152,436 136,002 1,642,123 ------------- ------------- ------------- ------------- Earnings before income tax expense 872,455 156,085 113,440 1,141,980 INCOME TAX EXPENSE Current 112,757 2,268 15,768 130,793 Deferred 185,231 67,318 28,296 280,845 ------------- ------------- ------------- ------------- Total income tax expense 297,988 69,586 44,064 411,638 ------------- ------------- ------------- ------------- Net earnings $ 574,467 86,499 69,376 730,342 ============= ============= ============= ============= Capital expenditures $ 893,087 202,673 184,372 1,280,132 ============= ============= ============= =============

80 17. SEGMENT INFORMATION (CONTINUED)

U.S. CANADA INTERNATIONAL TOTAL ------------- ------------- ------------- ------------- (IN THOUSANDS) AS OF DECEMBER 31, 1999: Current assets $ 391,328 69,279 129,687 590,294 Property and equipment, net of accumulated depreciation, depletion and amortization 3,424,415 467,465 531,540 4,423,420 Other assets 944,958 98 137,590 1,082,646 ------------- ------------- ------------- ------------- Total assets $ 4,760,701 536,842 798,817 6,096,360 ============= ============= ============= ============= Current liabilities 356,944 44,989 65,411 467,344 Long-term debt 2,077,180 339,341 -- 2,416,521 Deferred tax liabilities (assets) 340,514 1,733 (18,182) 324,065 Other liabilities 317,706 3,098 46,306 367,110 Stockholders' equity 1,668,357 147,681 705,282 2,521,320 ------------- ------------- ------------- ------------- Total liabilities and stockholders' equity $ 4,760,701 536,842 798,817 6,096,360 ============= ============= ============= ============= YEAR ENDED DECEMBER 31, 1999: REVENUES Oil sales $ 332,219 80,298 148,501 561,018 Gas sales 501,841 114,128 11,900 627,869 Natural gas liquids sales 57,610 10,075 300 67,985 Other 14,574 4,652 1,370 20,596 ------------- ------------- ------------- ------------- Total revenues 906,244 209,153 162,071 1,277,468 ------------- ------------- ------------- ------------- COSTS AND EXPENSES Lease operating expenses 188,576 49,831 60,400 298,807 Transportation costs 22,524 11,401 -- 33,925 Production taxes 42,977 1,363 400 44,740 Depreciation, depletion and amortization of property and equipment 309,292 65,176 31,907 406,375 Amortization of goodwill 16,106 -- 5 16,111 General and administrative expenses 68,807 12,189 (351) 80,645 Expenses related to mergers 16,800 -- -- 16,800 Interest expense 83,679 24,945 989 109,613 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 Reduction of carrying value of oil and gas properties 463,700 -- 12,400 476,100 ------------- ------------- ------------- ------------- Total costs and expenses 1,219,345 151,751 105,750 1,476,846 ------------- ------------- ------------- ------------- Earnings (loss) before income tax expense (benefit) and extraordinary item (313,101) 57,402 56,321 (199,378) INCOME TAX EXPENSE (BENEFIT) Current 15,348 2,908 4,800 23,056 Deferred (119,881) 26,654 20,737 (72,490) ------------- ------------- ------------- ------------- Total income tax expense (benefit) (104,533) 29,562 25,537 (49,434) ------------- ------------- ------------- ------------- Net earnings (loss) before extraordinary item (208,568) 27,840 30,784 (149,944) Extraordinary loss (4,200) -- -- (4,200) ------------- ------------- ------------- ------------- Net earnings (loss) $ (212,768) 27,840 30,784 (154,144) ============= ============= ============= ============= Capital expenditures $ 686,669 91,853 104,898 883,420 ============= ============= ============= =============

81 17. SEGMENT INFORMATION (CONTINUED)

U.S. CANADA INTERNATIONAL TOTAL ------------- ------------- ------------- ------------- (IN THOUSANDS) AS OF DECEMBER 31, 1998: Current assets $ 90,698 53,550 82,400 226,648 Property and equipment, net of accumulated depreciation, depletion and amortization 991,040 465,488 167,000 1,623,528 Deferred tax assets (liabilities) (36,093) 24,174 66,300 54,381 ------------- Other assets 17,126 1,454 7,400 25,980 ------------- ------------- ------------- ------------- Total assets $ 1,062,771 544,666 323,100 1,930,537 ============= ============= ============= ============= Current liabilities 119,132 55,624 45,100 219,856 Long-term debt 365,600 370,271 -- 735,871 Other liabilities 67,487 5,760 2,300 75,547 TCP Securities 149,500 -- -- 149,500 Stockholders' equity 361,052 113,011 275,700 749,763 ------------- ------------- ------------- ------------- Total liabilities and stockholders' equity $ 1,062,771 544,666 323,100 1,930,537 ============= ============= ============= ============= YEAR ENDED DECEMBER 31, 1998: REVENUES Oil sales $ 152,297 75,493 82,200 309,990 Gas sales 245,145 89,828 12,300 347,273 Natural gas liquids sales 19,871 4,644 200 24,715 Other 9,294 13,754 1,200 24,248 ------------- ------------- ------------- ------------- Total revenues 426,607 183,719 95,900 706,226 ------------- ------------- ------------- ------------- COSTS AND EXPENSES Lease operating expenses 127,451 47,910 51,200 226,561 Transportation costs 14,251 8,935 -- 23,186 Production taxes 22,910 1,661 300 24,871 Depreciation, depletion and amortization 165,654 44,590 32,900 243,144 of property and equipment General and administrative expenses 35,752 12,502 (2,800) 45,454 Expenses related to mergers 3,064 10,085 -- 13,149 Interest expense 20,558 21,974 1,000 43,532 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 301,400 -- 121,100 422,500 ------------- ------------- ------------- ------------- Total costs and expenses 700,757 163,761 203,700 1,068,218 ------------- ------------- ------------- ------------- Earnings (loss) before income tax expense (benefit) (274,150) 19,958 (107,800) (361,992) INCOME TAX EXPENSE (BENEFIT) Current (7,588) 1,975 1,900 (3,713) Deferred (92,360) 11,166 (41,200) (122,394) ------------- ------------- ------------- ------------- Total income tax expense (benefit) (99,948) 13,141 (39,300) (126,107) ------------- ------------- ------------- ------------- Net earnings (loss) $ (174,202) 6,817 (68,500) (235,885) ============= ============= ============= ============= Capital expenditures $ 347,634 205,178 160,000 712,812 ============= ============= ============= =============

82 18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED) Following is a summary of the unaudited interim results of operations for the years ended December 31, 2000 and 1999.

2000 ---------------------------------------------------------------------------- FIRST SECOND THIRD FOURTH FULL QUARTER QUARTER QUARTER QUARTER YEAR ------------ ------------ ------------ ------------ ------------ (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Oil, gas and natural gas liquids sales $ 548,351 635,777 695,475 838,842 2,718,445 Total revenues $ 560,416 648,484 725,141 850,062 2,784,103 Net earnings (loss) $ 105,187 153,334 164,912 306,909 730,342 Net earnings (loss) per common share: Basic $ 0.81 1.19 1.27 2.37 5.66 Diluted $ 0.80 1.17 1.22 2.27 5.50

1999 ----------------------------------------------------------------------------- FIRST SECOND THIRD FOURTH FULL QUARTER QUARTER QUARTER QUARTER YEAR ------------ ------------ ------------ ------------ ------------ (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Oil, gas and natural gas liquids sales $ 159,632 221,129 380,562 495,549 1,256,872 Total revenues $ 162,205 224,048 385,972 505,243 1,277,468 Net earnings (loss) $ 6,580 (286,491) 50,852 74,915 (154,144) Net earnings (loss) per common share: Basic $ 0.09 (3.55) 0.50 0.59 (1.68) Diluted $ 0.09 (3.55) 0.48 0.57 (1.68)

The third and fourth quarters of 2000 include $57.2 million and $3.2 million, respectively, of expenses incurred in connection with the Santa Fe Snyder merger. The after-tax effect of these expenses was $35.3 million and $1.9 million, respectively. The per share effect of these quarterly reductions was $0.28 and $0.01, respectively. The second and fourth quarters of 1999 include pre-tax reductions of the carrying value of oil and gas properties of $463.8 million and $12.3 million, respectively. The after-tax effects of these quarterly reductions were $301.7 million and $8.0 million, respectively. The per share effect of these quarterly reductions were $3.74 and $0.06, respectively. The second quarter of 1999 includes $16.8 million of expenses incurred in connection with the Snyder merger. The after-tax effect of these expenses was $10.9 million, or $0.14 per share. 83 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 29 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 23.5 Consent of KPMG LLP. 23.6 Consent of PricewaterhouseCoopers LLP 23.7 Consent of Deloitte & Touche LLP (b) Reports on Form 8-K -- A Current Report on Form 8-K dated December 12, 2000, was filed by the Registrant regarding year 2001 forward looking estimates. A Current Report on Form 8-K dated January 29, 2001, was filed by the Registrant regarding year-end 2000 oil and gas reserves and fixed prices of future oil and gas production. 84 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 December 18, 2001 By /s/ DANNY J. HEATLY ------------------------------------------ Danny J. Heatly Vice President -- Accounting 85 INDEX TO EXHIBITS

EXHIBIT NUMBER DESCRIPTION ------- ----------- 23.5 Consent of KPMG LLP 23.6 Consent of PricewaterhouseCoopers LLP 23.7 Consent of Deloitte & Touche LLP