UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D. C. 20549

                                    FORM 10-K
(Mark One)
  X           ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
-----                    SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 1999
                                       OR
            TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
------
                         SECURITIES EXCHANGE ACT OF 1934
                         Commission File Number 0-30176

                            DEVON ENERGY CORPORATION
             (Exact Name of Registrant as Specified in its Charter)

                  DELAWARE                                  73-1567067
       (State or Other Jurisdiction of                   (I.R.S. Employer
       Incorporation or Organization)                   Identification No.)
        20 NORTH BROADWAY, SUITE 1500
           OKLAHOMA CITY, OKLAHOMA                          73102-8260
   (Address of Principal Executive Offices)                  (Zip Code)	

Registrant's telephone number, including area code: (405) 235-3611
Securities registered pursuant to Section 12(b) of the Act:

                                                NAME OF EACH EXCHANGE
          TITLE OF EACH CLASS                    ON WHICH REGISTERED
          -------------------                   ---------------------

Common Stock, par value $.10 per share         American Stock Exchange
4.9% Convertible Debentures, due 2008          The New York Stock Exchange
4.95% Convertible Debentures, due 2008         The New York Stock Exchange	

Securities registered pursuant to Section 12(g) of the Act: NONE
INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR AT LEAST THE PAST 90 DAYS. YES X NO

INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO
ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED,
TO THE BEST OF REGISTRANT'S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. X

The aggregate market value of the voting stock held by non-affiliates of the Registrant as of March 15, 2000, was $3,465,818,453. At such date 81,763,318 shares of common stock and 4,583,804 exchangeable shares of Devon's wholly-owned subsidiary, Northstar Energy Corporation, were outstanding. Each exchangeable share is exchangeable for one share of Devon common stock.
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2000 annual meeting of stockholders - Part III

TABLE OF CONTENTS

                                                                                                              Page
                                                                                                              ----
PART I
    Item 1.  Business................................................................................            4
    Item 2.  Properties..............................................................................           12
    Item 3.  Legal Proceedings.......................................................................           18
    Item 4.  Submission of Matters to a Vote of Security Holders.....................................           20

PART II
    Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters...................           21
    Item 6.  Selected Financial Data.................................................................           22
    Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations...           25
    Item 7A. Quantitative and Qualitative Disclosures About Market Risk..............................           45
    Item 8.  Financial Statements and Supplementary Data.............................................           47
    Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure....          105

PART III
    Item 10.  Directors and Executive Officers of the Registrant.....................................          105
    Item 11.  Executive Compensation.................................................................          105
    Item 12.  Security Ownership of Certain Beneficial Owners and Management.........................          105
    Item 13.  Certain Relationships and Related Transactions.........................................          105

PART IV
    Item 14.  Exhibits, Financial Statements and Schedules, and Reports on Form 8-K..................          106	

DEFINITIONS

                       As used in this document:
                    "Mcf" means thousand cubic feet
                    "MMcf" means million cubic feet
                    "Bcf" means billion cubic feet
"MMBtu" means million British thermal units, a measure of heating value
                          "Bbl" means barrel
                    "MBbls" means thousand barrels
                    "MMBbls" means million barrels
                 "Boe" means equivalent barrels of oil
            "MBoe" means thousand equivalent barrels of oil
            "MMBoe" means million equivalent barrels of oil
                "Oil" includes crude oil and condensate
                   "NGLs" means natural gas liquids	

"Southern Division" means the division of the Company encompassing oil and gas properties located primarily in the onshore south Texas and Gulf Coast areas and offshore in the Gulf of Mexico "Northern Division" means the division of the Company encompassing oil and gas properties located in the United States other than those within the Southern Division "International Division" means the division of the Company encompassing oil and gas properties that lie outside the United States and Canada "Canada" means the division of the Company encompassing oil and gas properties that are located in Canada. All of these properties are held in the Company's wholly-owned subsidiary, Northstar Energy Corporation.
2

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
THIS REPORT INCLUDES "FORWARD-LOOKING STATEMENTS" WITHIN THE MEANING OF
SECTION 27A OF THE SECURITIES ACT OF 1933, AS AMENDED, AND SECTION 21E OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED. ALL STATEMENTS OTHER THAN STATEMENTS OF HISTORICAL FACTS INCLUDED OR INCORPORATED BY REFERENCE IN THIS REPORT, INCLUDING, WITHOUT LIMITATION, STATEMENTS REGARDING THE COMPANY'S FUTURE FINANCIAL POSITION, BUSINESS STRATEGY, BUDGETS, PROJECTED COSTS AND PLANS AND OBJECTIVES OF MANAGEMENT FOR FUTURE OPERATIONS, ARE FORWARD-LOOKING STATEMENTS. IN ADDITION, FORWARD-LOOKING STATEMENTS GENERALLY CAN BE IDENTIFIED BY THE USE OF FORWARD-LOOKING TERMINOLOGY SUCH AS "MAY," "WILL," "EXPECT," "INTEND," "PROJECT," "ESTIMATE," "ANTICIPATE," "BELIEVE," OR "CONTINUE" OR THE NEGATIVE THEREOF OR VARIATIONS THEREON OR SIMILAR TERMINOLOGY. ALTHOUGH THE COMPANY BELIEVES THAT THE EXPECTATIONS REFLECTED IN SUCH FORWARD-LOOKING STATEMENTS ARE REASONABLE, IT CAN GIVE NO ASSURANCE THAT SUCH EXPECTATIONS WILL PROVE TO HAVE BEEN CORRECT. IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE COMPANY'S EXPECTATIONS ("CAUTIONARY STATEMENTS") ARE DISCLOSED UNDER "ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS," "ITEM 2. PROPERTIES - PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE" AND ELSEWHERE IN THIS REPORT. ALL SUBSEQUENT WRITTEN AND ORAL FORWARD-LOOKING STATEMENTS ATTRIBUTABLE TO THE COMPANY, OR PERSONS ACTING ON ITS BEHALF, ARE EXPRESSLY QUALIFIED IN THEIR ENTIRETY BY THE CAUTIONARY STATEMENTS. THE COMPANY ASSUMES NO DUTY TO UPDATE OR REVISE ITS FORWARD-LOOKING STATEMENTS BASED ON CHANGES IN INTERNAL ESTIMATES OR EXPECTATIONS OR OTHERWISE.
3

PART I
ITEM 1. BUSINESS
GENERAL
Devon Energy Corporation, including its subsidiaries, ("Devon" or the "Company") is an independent energy company engaged primarily in oil and gas exploration, development and production, and in the acquisition of producing properties. Through its predecessors, Devon began operations in 1971 as a privately-held company. In 1988 the Company's common stock began trading publicly on the American Stock Exchange under the symbol DVN. In addition, commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange under the symbol NSX. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon's wholly-owned subsidiary, Northstar Energy Corporation ("Northstar"), they qualify as a domestic Canadian investment for Canadian institutional shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon.
The principal and administrative offices of Devon are located at 20 North Broadway, Suite 1500, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
Devon currently owns oil and gas properties concentrated in four operating divisions: the Northern Division, which encompasses properties in the Permian Basin, Rocky Mountains and Mid-Continent; the Southern Division, which encompasses properties in south Texas, the Gulf Coast area and offshore Gulf of Mexico; Canada, which includes properties in the Western Canadian Sedimentary Basin in Alberta and British Columbia; and the International Division, which includes properties in Azerbaijan, Egypt, Qatar, Brazil, Australia and Venezuela. (A detailed description of the significant properties can be found under "Item 2. Properties - Significant Properties" beginning on page 12 hereof.)
At December 31, 1999, Devon's estimated proved reserves were 669.8 MMBoe, of which 47% were natural gas reserves and 53% were oil and NGLs reserves. The present value of pre-tax future net revenues discounted at 10% per annum assuming essentially unescalated prices ("10% Present Value") of such reserves was $3.6 billion. Devon is one of the top 10 public independent oil and gas companies based in the United States, as measured by oil and gas reserves.
STRATEGY
Devon's primary objectives are to build production, cash flow and earnings per share by (a) acquiring oil and gas properties, (b) exploring for new oil and gas reserves and (c) optimizing production from existing oil and gas properties. Devon's management seeks to achieve these objectives by (a) keeping debt levels low, (b) concentrating its properties in core areas to achieve economies of scale, (c) acquiring and developing high profit margin properties,
(d) continually disposing of marginal and non-strategic properties and (e) balancing reserves between oil and gas.
4

During 1988, Devon expanded its capital base with its first issuance of common stock to the public. This transaction began a substantial expansion program that has continued through the subsequent years. Devon has used a two-pronged strategy of acquiring producing properties and engaging in drilling activities to achieve this expansion. Total proved reserves increased from 8.1 MMBoe at year-end 1987 to 669.8 MMBoe at year-end 1999.
Devon's objective, however, is to increase value per share, not simply to increase total assets. Reserves have grown from 1.31 Boe per share at year-end 1987 to 7.78 Boe per share at year-end 1999. At the same time, net debt (long-term debt less working capital and marketable securities) has remained relatively low. At year-end 1999, Devon's net debt was $1.47 per Boe.
RECENT DEVELOPMENTS
On August 17, 1999, Devon completed a merger with PennzEnergy Company ("PennzEnergy"). PennzEnergy's domestic operations were focused in the Gulf of Mexico, onshore Gulf Coast, east and west Texas, and New Mexico. It had international operations located in Australia, Azerbaijan, Brazil, Egypt, Qatar and Venezuela. The merger of PennzEnergy with Devon expanded Devon's reserves by approximately 396 MMBoe, approximately 13 million net acres of undeveloped leasehold and $3.2 billion of assets. The total consideration to PennzEnergy was 21.5 million common shares and the assumption of $2.3 billion of PennzEnergy debt. At year-end 1999, Devon's unused borrowing capacity was in excess of $435 million.
The PennzEnergy merger was accounted for under the purchase method of accounting for business combinations. Therefore, Devon's 1999 results do not include any effect of PennzEnergy's operations prior to August 17, 1999.
The PennzEnergy merger was completed less than a year after Devon's merger with Northstar. The December 10, 1998, combination of Devon and Northstar added 115 MMBoe of proved reserves and 1.8 million undeveloped acres, all in Canada. The Northstar combination was accounted for under the pooling-of-interests method of accounting for business combinations. Accordingly, Devon's results for 1998 and prior years include the results of both Devon and Northstar as if the two had always been combined.
In addition to the two mergers, Devon's exploration, drilling and development efforts have also been significant contributors to Devon's growth over the last three years. Excluding the pooled results of Northstar prior to December 1998, Devon has spent approximately $492 million in its exploration, drilling and development efforts from 1997 through 1999. These costs included drilling 1,154 wells, of which 1,065 were completed as producers.
DRILLING ACTIVITIES
Devon is engaged in numerous drilling activities on properties presently owned and intends to drill or develop other properties acquired in the future. For 2000, Devon's drilling activities will be focused in the Rocky Mountains, Permian Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas in the U.S. and the Western Sedimentary areas of Canada.
5

The following tables set forth the results of Devon's drilling activity for the past five years.
UNITED STATES PROPERTIES

                            Development Wells                                           Exploratory Wells
         ----------------------------------------------------------  ---------------------------------------------------------
                     Gross (1)                    Net (2)                     Gross (1)                       Net(2)
         ----------------------------------------------------------  ---------------------------------------------------------
         Productive    Dry     Total   Productive    Dry     Total   Productive   Dry     Total   Productive    Dry     Total
         ----------    ---     ------  ----------    ---    -------  ----------   ---     -----   ----------    -----  -------
1995            184        3      187      143.87     0.29   144.16           9       3      12         2.53     1.18     3.71
1996            188        3      191      137.05     0.95   138.00           2       1       3         1.50     0.08     1.58
1997            244        9      253      109.00     4.90   113.90          14       2      16         5.00     1.50     6.50
1998            328        0      328      128.69     0.00   128.69          14       4      18         7.36     1.44     8.80
1999            476        5      481      300.25     1.50   301.75          58       3      61        46.51     1.98    48.49
             ------      ---   ------     -------    -----  -------         ---     ---   -----       ------    -----  -------
Total         1,420       19    1,440      818.86     7.64   826.50          97      13     110        62.90     6.18    69.08
             ======      ===   ======     =======    =====  =======         ===     ===   =====       ======    =====  =======	

CANADIAN PROPERTIES

                            Development Wells                                           Exploratory Wells
         ----------------------------------------------------------  ---------------------------------------------------------
                     Gross (1)                    Net (2)                     Gross (1)                       Net(2)
         ----------------------------------------------------------  ---------------------------------------------------------
         Productive    Dry     Total   Productive    Dry     Total   Productive   Dry     Total   Productive    Dry     Total
         ----------    ---     ------  ----------    ---    -------  ----------   ---     -----   ----------   ------  -------
1995             44        8       52       25.20     5.20    30.40          48      13      61        35.70    10.00    45.70
1996             63       11       74       29.70     5.10    34.80          35      18      53        24.70    15.10    39.80
1997            126       29      155       88.20    23.20   111.40          55      48     103        43.50    42.20    85.70
1998            112       15      127       74.88    11.04    85.92          45      37      82        32.99    30.50    63.49
1999             65        9       74       29.61     3.45    33.06          39      23      62        25.15    16.03    41.18
             ------      ---   ------     -------    -----  -------         ---     ---   -----       ------   ------  -------
Total           410       72      482      247.59    47.99   295.58         222     139     361       162.04   113.83   275.87
             ======      ===   ======     =======    =====  =======         ===     ===   =====       ======   ======  =======	

INTERNATIONAL PROPERTIES

                            Development Wells                                           Exploratory Wells
         ----------------------------------------------------------  ---------------------------------------------------------
                     Gross (1)                    Net (2)                     Gross (1)                       Net(2)
         ----------------------------------------------------------  ---------------------------------------------------------
         Productive     Dry    Total   Productive    Dry     Total   Productive    Dry    Total   Productive     Dry    Total
         ----------    -----   ------  ----------    -----  -------  ----------   -----   -----   ----------    -----  -------
1999             --       --       --          --       --       --          --      --      --           --       --       --
             ------      ---   ------     -------    -----  -------         ---     ---   -----       ------    -----  -------
Total            --       --       --          --       --       --          --      --      --           --       --       --
             ======      ===   ======     =======    =====  =======         ===     ===   =====       ======    =====  =======	

TOTAL PROPERTIES

                            Development Wells                                           Exploratory Wells
         ----------------------------------------------------------  ---------------------------------------------------------
                     Gross (1)                    Net (2)                     Gross (1)                       Net(2)
         ----------------------------------------------------------  ---------------------------------------------------------
         Productive     Dry    Total   Productive    Dry    Total    Productive    Dry    Total   Productive    Dry     Total
         ----------    -----   ------  ----------    ----- --------  ----------   -----   -----   ----------  -------  -------
1995            228       11      239      169.07     5.49   174.56          57      16      73        38.23    11.18    49.41
1996            251       14      265      166.75     6.05   172.80          37      19      56        26.20    15.18    41.38
1997            370       38      408      197.20    28.10   225.30          69      50     119        48.50    43.70    92.20
1998            440       15      455      203.57    11.04   214.61          59      41     100        40.35    31.94    72.29
1999            541       14      555      329.86     4.95   334.81          97      26     123        71.66    18.01    89.67
             ------      ---   ------   ---------    ----- --------         ---     ---   -----       ------  -------  -------
Total         1,830       92    1,922    1,066.45    55.63 1,122.08         319     152     471       224.94   120.01   344.95
             ======      ===   ======   =========    ===== ========         ===     ===   =====       ======  =======  =======	

(1) Gross wells are the sum of all wells in which Devon owns an interest.
(2) Net wells are the sum of Devon's working interests in gross wells.
As of December 31, 1999, Devon was participating in the drilling of 80 gross (50.30 net) wells in the U.S. and 8 gross (4.20 net) wells in Canada. Of these wells, through March 1, 2000, 23 gross (16.10 net) wells in the U.S. and 2 gross (.78 net) wells in Canada had been completed as productive. An additional 1 gross (0.60 net) well in the U.S. and 2 gross (1.17 net) wells in Canada were dry holes. The remaining wells were still in process.
6

CUSTOMERS
Devon sells its gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Existing gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.
The principal customers for Devon's crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or barged to storage, refining or pipeline facilities.
For the year ended December 31, 1999, one significant purchaser, Columbia Energy Services Corporation ("Columbia"), accounted for 12% of Devon's combined oil, gas and NGLs sales. For the years ended 1998 and 1997, one significant purchaser, Aquila Energy Marketing Corporation ("Aquila"), accounted for 19% and 15%, respectively, of Devon's total revenue. Columbia and Aquila purchase production from numerous Devon properties, at variable and market-sensitive prices. Devon does not consider itself dependent upon either of these purchasers, since other purchasers are willing to purchase this same production at competitive prices.
OIL AND NATURAL GAS MARKETING
Oil Marketing. Devon's oil production is sold under both long-term and short-term agreements at prices negotiated between the parties. Devon periodically enters into hedging activities with a portion of its oil production which are intended to support its oil price at targeted levels and to manage the Company's exposure to oil price fluctuations. (See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk.")
Natural Gas Marketing. Devon's gas production is also sold under both long-term and short-term agreements at negotiated prices. Although exact percentages vary daily, as of March 2000 approximately 20% of Devon's natural gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as "spot market" sales. Another 65% were committed under various long-term contracts (one year or more) which dedicate the natural gas to a purchaser for an extended period of time, but still at market sensitive prices. Devon's remaining gas production was dedicated under long-term contracts at fixed prices.
Under both long-term and short-term contracts, typically either the entire contract (in the case of short-term contracts) or the price provisions of the contract (in the case of long-term contracts) are renegotiated from daily intervals up to one-year intervals. The spot market has become progressively more competitive in recent years. As a result, prices on the spot market have been volatile.
The spot market is subject to volatility as supply and demand factors in various regions of North America fluctuate. In addition to long-term fixed price contracts, Devon periodically enters into hedging arrangements or firm delivery commitments with a portion of its gas production. These activities are intended to support targeted gas price levels and to manage the Company's exposure to gas price fluctuations. (See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk.")
7

COMPETITION
The oil and gas business is highly competitive. Devon encounters competition by major integrated and independent oil and gas companies in acquiring drilling prospects and properties, contracting for drilling equipment and securing trained personnel. Intense competition occurs with respect to marketing, particularly of natural gas. Certain competitors have resources that substantially exceed those of Devon.
SEASONAL NATURE OF BUSINESS
Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
GOVERNMENT REGULATION
Devon's operations are subject to various levels of government controls and regulations in the United States, Canada and internationally.
UNITED STATES REGULATION
In the United States, legislation affecting the oil and gas industry has been pervasive and is under constant review for amendment or expansion. Pursuant to such legislation, numerous federal, state and local departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas drilling and production activities, increase the cost of doing business and, consequently, affect profitability. Inasmuch as new legislation affecting the oil and gas industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, Devon is unable to predict the future cost or impact of complying with such laws and regulations.
Exploration and Production. Devon's United States operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Devon's operations are also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas Devon can produce from its wells and to limit the number of wells or the locations at which Devon can drill.
8

Certain of Devon's oil and gas leases, including most of its leases in the San Juan Basin and many of the Company's leases in southeast New Mexico and Wyoming, are granted by the federal government and administered by various federal agencies. Such leases require compliance with detailed federal regulations and orders which regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government.
Federal regulation of Devon's offshore Gulf of Mexico leases is accomplished by the Minerals Management Service of the Department of the Interior (`MMS"). The MMS has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands. The FERC also has jurisdiction over certain offshore activities pursuant to the Outer Continental Shelf Lands Act.
Environmental and Occupational Regulations. Various federal, state and local laws and regulations concerning the discharge of incidental materials into the environment, the generation, storage, transportation and disposal of contaminants or otherwise relating to the protection of public health, natural resources, wildlife and the environment, affect Devon's exploration, development and production operations and the costs attendant thereto. These laws and regulations increase Devon's overall operating expenses. Devon maintains levels of insurance customary in the industry to limit its financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, 100% coverage is not maintained concerning any environmental claim, and no coverage is maintained with respect to any award of punitive damages against Devon or any penalty or fine required to be paid by Devon because of its violation of any federal, state or local law. Devon is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Devon's unreimbursed expenditures in 1999 concerning such matters were immaterial, but Devon cannot predict with any reasonable degree of certainty its future exposure concerning such matters.
Devon is also subject to laws and regulations concerning occupational safety and health. Due to the continued changes in these laws and regulations, and the judicial construction of same, Devon is unable to predict with any reasonable degree of certainty its future costs of complying with these laws and regulations.
Since 1993, Devon has had its own internal Environmental Health and Safety Department. This department is responsible for instituting and maintaining an environmental and safety compliance program for Devon. The program includes field inspections of properties and internal assessments of Devon's compliance procedures.
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and similar state statutes. In response to potential liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no claims for possible recovery from third party insurers or other parties related to environmental costs have been
9

recognized in Devon's consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
Certain of Devon's subsidiaries acquired in the PennzEnergy merger are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of December 31, 1999, Devon's consolidated balance sheet included $6.7 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is based in large part on (i) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material.
CANADIAN REGULATIONS
The oil and gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect Devon's Canadian operations in a manner materially different than they would affect other oil and gas companies of similar size. The following are the most important areas of control and regulation.
The North American Free Trade Agreement. The North American Free Trade Agreement ("NAFTA") which became effective on January 1, 1994 carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not (i) reduce the proportion of energy exported relative to the supply of the energy resource; (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All parties to NAFTA are also prohibited from imposing minimum export or import price requirements.
Royalties and Incentives. Each province and the federal government of Canada have legislation and regulations governing land tenure, royalties, production rates and taxes, environmental protection and other matters under their respective jurisdictions. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location, field discovery date and the type and quality of the petroleum product produced. From time to time, the governments of Canada, Alberta and British Columbia have also established incentive programs such as royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing the cash flow to the producer.
Pricing and Marketing. The price of oil and natural gas sold is determined by negotiation between buyers and sellers. An order from the National Energy Board ("NEB") is required for oil exports from Canada. Any oil export to be made pursuant to an export contract of longer than one
10

year, in the case of light crude, and two years, in the case of heavy crude, duration (up to 25 years) requires an exporter to obtain an export license from the NEB. The issue of such a license requires the approval of the Governor in Council. Natural gas exported from Canada is also subject to similar regulation by the NEB. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts in excess of two years must continue to meet certain criteria prescribed by the NEB. The governments of Alberta and British Columbia also regulate the volume of natural gas which may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.
Environmental Regulation. The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. A breach of such legislation may result in the imposition of fines and penalties. Devon is committed to meeting its responsibilities to protect the environment wherever it operates and anticipates making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment. Devon's unreimbursed expenditures in 1999 concerning such matters were immaterial, but Devon cannot predict with any reasonable degree of certainty its future exposure concerning such matters.
Investment Canada Act. The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction requiring such approval.
INTERNATIONAL REGULATIONS
Environmental Regulation. The oil and gas industry is subject to various environmental regulation and contract concession requirements pursuant to each individual country's laws, agreements, and treaties. In general, this consists of preparing Environmental Impact Assessments in order to receive required environmental permits to conduct any type of drilling or construction activity. Such regulations also typically include requirements to develop emergency response plans, waste management plans, and spill contingency plans. In some regions, the application of world-wide standards, such as, ISO 14000 governing Environmental Management Systems are required to be implemented for operations.
Protecting the environment and the safety and health of employees, contractors, communities, and the public is fundamental to the way Devon conducts its business. This is accomplished through the establishment of corporate environmental, health, and safety policies and procedures that are implemented worldwide.
EMPLOYEES
As of December 31, 1999, Devon's staff consisted of 1,549 full-time employees, including 162 professionals in engineering, 90 in geology, 61 in the land department, 28 in oil and gas marketing, 226 in accounting and data processing, and 170 in administration and other support positions. Included in the number, are 148 former employees of PennzEnergy whose services will be terminated at various times during the year 2000. The Company also engages independent consulting petroleum engineers,
11

environmental professionals, geologists, geophysicists, landmen and attorneys on a fee basis.
ITEM 2. PROPERTIES
Substantially all of Devon's properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage located in the Company's core operating areas. These interests entitle Devon to drill for and produce oil, natural gas and NGLs from specific areas. Devon's interests are mostly in the form of working interests and volumetric production payments, and, to a lesser extent, overriding royalty, foreign government concessions, mineral and net profits interests and other forms of direct and indirect ownership in oil and gas properties.
PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE
"Proved reserves" are those quantities of oil, natural gas and NGLs, which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Estimates of proved reserves are strictly technical judgments and are not knowingly influenced by attitudes of conservatism or optimism. The following table sets forth Devon's estimated proved reserves, the estimated future net revenues therefrom and the 10% Present Value thereof as of December 31, 1999. Approximately 97% of Devon's U.S. proved reserves were estimated by LaRoche Petroleum Consultants, Ltd. and Ryder-Scott Company Petroleum Consultants, independent petroleum consultants. Devon's internal staff of engineers estimated the remainder of the U.S. reserves. All of the year-end 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates Ltd. The international proved reserves, other than Canada as of December 31, 1999, were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants. All reserve estimates were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines (as described in the following notes). These estimates correspond with the method used in presenting the `Supplemental Information on Oil and Gas Operations" in Note 16 to Devon's Consolidated Financial Statements included herein, except that federal income taxes attributable to such future net revenues have been disregarded in the presentation below.
12

                                                              TOTAL       PROVED         PROVED
                                                             PROVED      DEVELOPED     UNDEVELOPED
                                                            RESERVES    RESERVES (1)   RESERVES (2)
                                                           ----------   ------------   ------------
TOTAL RESERVES
         Oil (MBbls) ....................................     303,917        171,249        132,668
         Gas (MMcf) .....................................   1,896,527      1,751,385        145,142
         NGLs (MBbl) ....................................      49,817         47,502          2,315
         MBoe (3) .......................................     669,822        510,649        159,173
         Pre-tax Future Net Revenue ($ thousands)(4) ....   6,712,759      4,843,728      1,869,031
         Pre-tax 10% Present Value ($ thousands)(4) .....   3,634,023      3,027,305        606,718

U.S. RESERVES
         Oil (MBbls) ....................................     145,524        128,167         17,357
         Gas (MMcf) .....................................   1,384,086      1,246,131        137,955
         NGLs (MBbl) ....................................      45,804         43,637          2,167
         MBoe (3) .......................................     422,009        379,493         42,516
         Pre-tax Future Net Revenue ($ thousands)(4) ....   4,094,550      3,740,386        354,164
         Pre-tax 10% Present Value ($ thousands)(4) .....   2,503,341      2,331,613        171,728

CANADIAN RESERVES
         Oil (MBbls) ....................................      32,132         29,268          2,864
         Gas (MMcf) .....................................     506,218        501,376          4,842
         NGLs (MBbl) ....................................       4,013          3,865            148
         MBoe (3) .......................................     120,515        116,696          3,819
         Pre-tax Future Net Revenue ($ thousands)(4) ....   1,084,902      1,032,242         52,660
         Pre-tax 10% Present Value ($ thousands)(4) .....     689,777        659,082         30,695

INTERNATIONAL RESERVES
         Oil (MBbls) ....................................     126,261         13,814        112,447
         Gas (MMcf) .....................................       6,223          3,878          2,345
         NGLs (MBbl) ....................................          --             --             --
         MBoe (3) .......................................     127,298         14,460        112,838
         Pre-tax Future Net Revenue ($ thousands)(4) ....   1,533,307         71,100      1,462,207
         Pre-tax 10% Present Value ($ thousands)(4) .....     440,905         36,610        404,295	

(1) Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.
(2) Proved undeveloped reserves are proved reserves to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompleting or deepening a well or for new fluid injection facilities.
(3) Gas reserves are converted to MBoe at the rate of six MMcf per MBbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. The respective prices of gas and oil are affected by market conditions and other factors in addition to relative energy content.
(4) Estimated future net revenue represents estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and development costs. The amounts shown do not give effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization.
These amounts were calculated using prices and costs in effect as of December 31, 1999. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yield average prices over the life of Devon's properties of $21.96 per Bbl of oil, $1.87 per Mcf of natural gas and $15.74 per Bbl of NGLs. These prices compare to December 31, 1999, benchmark posted prices of $22.75 per Bbl for West Texas Intermediate crude oil and a composite of $2.03 per MMBtu for Texas Gulf Coast spot gas for gas delivered to various Texas Gulf Coast pipelines.
13

No estimates of Devon's proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of the last fiscal year except (i) in filings with the SEC and (ii) in filings with the Department of Energy ("DOE"). Reserve estimates filed by Devon with the SEC correspond with the estimates of Devon reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Devon's reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that Devon operates and to exclude all interests in wells that Devon does not operate.
The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 1999. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
The process of estimating oil, gas and NGLs reserves is complex, requiring significant subjective decisions in the evaluation of available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur in the future.
PRODUCTION, REVENUE AND PRICE HISTORY
Certain information concerning oil and natural gas production, prices, revenues (net of all royalties, overriding royalties and other third party interests) and operating expenses for the three years ended December 31, 1999, is set forth in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
WELL STATISTICS
The following table sets forth Devon's producing wells as of December 31, 1999:

                      Oil Wells                   Gas Wells                    Total Wells
               ------------------------    -------------------------     ------------------------
                Gross (1)     Net (2)       Gross (1)     Net (2)         Gross (1)    Net (2)
               ------------- ----------    ------------ ------------     ------------ -----------
U.S.                  12,999      4,090           5,238        2,667           18,237       6,757
Canada                 1,636        556           1,374          539            3,010       1,095
International            154         82               3            2              157          84
               ------------- ----------    ------------ ------------     ------------ -----------
Total                 14,789      4,728           6,615        3,208           21,404       7,936
               ============= ==========    ============ ============     ============ ===========	

(1) Gross wells are the total number of wells in which Devon owns a working interest.
(2) Net refers to gross wells multiplied by Devon's fractional working interests therein.
Devon also held numerous overriding royalty interests in oil and gas wells, a portion of which are convertible to working interests after recovery of certain costs by third parties. After converting to working interests, these overriding royalty interests will be included in Devon's gross and net well count.
14

UNDEVELOPED ACREAGE
The following table sets forth Devon's developed and undeveloped oil and gas lease and mineral acreage as of December 31, 1999.

                                                  Developed                    Undeveloped
                                          ------------------------     ------------------------
                                           Gross (1)     Net (2)         Gross (1)    Net (2)
                                          ------------ -----------     ------------ -----------
Northern Division
           Permian Basin                       582,390     259,741          793,033     201,473
           Rocky Mountains                     407,139     168,146        1,524,306   1,186,264
           Mid-Continent & Other             1,253,368     867,184          927,140     412,232
                                          ------------ -----------     ------------ -----------
           Total Northern Division           2,242,897   1,295,071        3,244,479   1,799,969
                                          ------------ -----------     ------------ -----------
Southern Division
           Offshore                            320,056     207,908          501,649     371,713
           Onshore                             397,475     259,740          108,128      40,959
                                          ------------ -----------     ------------ -----------
           Total Southern Division             717,531     467,648          609,777     412,672
                                          ------------ -----------     ------------ -----------
Canada                                        873,280    469,026          3,074,357   2,205,606
International Division                         31,100     11,253         12,714,589  11,634,351
                                          ------------ -----------     ------------ -----------
Grand Total                                  3,864,808   2,242,998       19,643,202  16,052,598
                                          ============ ===========     ============ ===========	

(1) Gross acres are the total number of acres in which Devon owns a working interest.
(2) Net refers to gross acres multiplied by Devon's fractional working interests therein.
OPERATION OF PROPERTIES
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions. The charges under operating agreements customarily vary with the depth and location of the well being operated.
Devon is the operator of 8,913 of its wells. As operator, Devon receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area to or by unaffiliated third parties. In presenting its financial data, Devon records the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.
SIGNIFICANT PROPERTIES
The following table sets forth proved reserve information on the most significant geographic areas in which Devon's properties are located as of December 31, 1999.
15

                                                                                           10% PRESENT
                                                                                            VALUE(3)     10% PRESENT
                            OIL(MBBLS)   GAS(MMCF)    NGLS(MBBL)    MBOE(1)      MBOE%(2)    ($000)       VALUE%(4)
                            ----------   ----------   ----------    --------     --------- -----------   -----------
NORTHERN DIVISION
   Permian Basin                68,200      206,425       17,707     120,312       17.9%   $   797,017          21.9%
   Rocky Mountains              35,167      437,495        5,689     113,771       17.0%       602,810          16.6%
   Mid-Continent & Other        15,624      420,570       17,226     102,945       15.4%       535,211          14.7%
                            ----------   ----------   ----------    --------      -----    -----------    ----------
      Total                    118,991    1,064,490       40,622     337,028       50.3%     1,935,038          53.2%
                            ----------   ----------   ----------    --------      -----    -----------    ----------

SOUTHERN DIVISION
   Offshore                     16,670      216,387        3,645      56,380        8.4%       376,828          10.4%
   Onshore                       9,863      103,209        1,537      28,601        4.3%       191,475           5.3%
                            ----------   ----------   ----------    --------      -----    -----------    ----------
      Total                     26,533      319,596        5,182      84,981       12.7%       568,303          15.7%
                            ----------   ----------   ----------    --------      -----    -----------    ----------
      Total U.S.               145,524    1,384,086       45,804     422,009       63.0%     2,503,341          68.9%
                            ----------   ----------   ----------    --------      -----    -----------    ----------

CANADA
      Total                     32,132      506,218        4,013     120,515       18.0%       689,777(5)       19.0%
                            ----------   ----------   ----------    --------      -----    -----------    ----------

INTERNATIONAL DIVISION
      Total                    126,261        6,223           --     127,298       19.0%       440,905          12.1%
                            ----------   ----------   ----------    --------      -----    -----------    ----------
Grand Total                    303,917    1,896,527       49,817     669,822      100.0%   $ 3,634,023         100.0%
                            ==========   ==========   ==========    ========      =====    ===========    ==========	

(1) Gas reserves are converted to MBoe at the rate of six MMcf of gas per MBbl of oil, based upon the approximate relative energy content of natural gas to oil, which rate is not necessarily indicative of the relationship of gas to oil prices. The respective prices of gas and oil are affected by market and other factors in addition to relative energy content.
(2) Percentage which MBoe for the basin or region bears to total MBoe for all Proved Reserves.
(3) Determined in accordance with SEC guidelines, except that no effect is given to future income taxes.
(4) Percentages which present value for the basin or region bears to total present value for all Proved Reserves.
(5) Canadian dollars converted to U.S. dollars at the rate of $1 Canadian:
$0.6929 U.S.
NORTHERN DIVISION PROPERTIES
PERMIAN BASIN. This region encompasses approximately 66,000 square miles in southeastern New Mexico and west Texas and contains more than 500 major oil and gas fields. Since 1987, several significant acquisitions of properties by Devon in the Permian Basin have established prospective acreage in areas in which leasehold positions could not otherwise be obtained. It is characterized by prolific, long-lived oil and gas production from numerous formations found at a wide variety of depths. Many formations respond to enhanced recovery techniques, such as waterflood projects. In addition, the region is criss-crossed with multiple pipelines with easy access to many oil and gas markets. Acreage held by production from existing wells and large federal exploration units makes leases difficult to obtain. Most of Devon's position here was established through five major transactions.
ROCKY MOUNTAINS. Over a dozen oil and gas producing basins are located in the Rocky Mountain area, stretching from the Canadian border south to New Mexico. The Rocky Mountain area includes Devon's operations in three coalbed methane basins: The San Juan Basin in northwest New Mexico and southern Colorado, the Powder River Basin in Wyoming and the Raton Basin of northeastern New Mexico. Technology pioneered by Devon and a few other companies in the 1980's and 1990's resulted in significant production from coalbeds in the San Juan Basin. Devon is now applying its expertise to the development of coalbed reservoirs in the Powder River and Raton Basins. Over the next few years, Devon anticipates significant growth in its gas production from these two basins as wells are drilled and tied into pipelines.
16

Devon's largest natural gas reserve position in the Rocky Mountain Region relates to its interests in two federal units in the San Juan Basin. The San Juan Basin is a densely drilled area covering 3,700 square miles.
Devon's coal seam expertise will also play an important role in both the Powder River and Raton Basins. These basins, which are less developed than the San Juan Basin, have become two of the more active domestic onshore exploration areas in the United States. During the next five years, Devon plans to drill several thousand coalbed methane wells in the Powder River and Raton Basins which could, in aggregate, add significant proved natural gas reserves. Peak production for the Powder River Basin is anticipated for 2003, while peak production in the Raton Basin is estimated for 2004 to 2006. Additionally, Devon began initial operation of a 126-mile gas gathering system servicing the Powder River Basin in the third quarter of 1999. When it is fully developed in 2001, this system will have an estimated capacity of 450 million cubic feet of gas per day and will have access to multiple interstate pipelines.
MID-CONTINENT. The Mid-Continent area includes all or portions of the states of Kansas, Oklahoma, Texas, Arkansas, Louisiana, Mississippi and Alabama. The area covers a wide spectrum of geologic formations producing both oil and natural gas. Although the Mid-Continent was the site of some of the earliest oil and gas discoveries in the United States, the area continues to offer exploration potential. New technologies such as 3-D seismic are enabling Devon to study complex geologic environments and identify new exploratory prospects. Nuclear magnetic resonance logging is being applied by Devon in the Carthage-Bethany area of east Texas. Devon acquired its position in Carthage-Bethany in the PennzEnergy merger. Previously bypassed reserves are being discovered in wells in Carthage-Bethany through application of this new reserve evaluation technology.
SOUTHERN DIVISION PROPERTIES
ONSHORE. Devon's Gulf Coast area includes lands in south Texas and south Louisiana. In south Texas, where exploration for oil and gas is accelerating, Devon has 3-D seismic data covering its major acreage positions. This acreage is prospective for production in the Charco Lobo, Middle Wilcox and Frio-Vicksburg formations. The Company's exploration efforts in south Louisiana are focused on natural gas prospects in the lower, mid and upper Miocene age formations. The Gulf Coast area provides ready access to pipelines and production facilities. Natural gas from the Gulf Coast is typically priced at a premium to other U.S. producing areas.
OFFSHORE. The offshore Gulf of Mexico is a prolific producing area that provides approximately 25% of the natural gas produced in the United States. With a substantial infrastructure of platforms and production facilities, Devon is one of the largest operators on the shallow-water "shelf." Producing gas wells on the shelf are known for providing high initial flow rates and quick investment returns. As deep water drilling and production technology improves, operators are moving into the waters beyond the shelf. Technology now exists to drill and produce oil at water depths of 3,000 feet and deeper. The deep water Gulf of Mexico is believed to hold some of North America's largest remaining undiscovered oil and gas reserves. Devon has a substantial inventory of exploration acreage in the deeper Gulf waters.
17

CANADIAN PROPERTIES
Western Canada is Devon's largest production area. The Western Canadian Sedimentary Basin is a vast geologic feature encompassing portions of British Columbia, Alberta, Saskatchewan and Manitoba. The basin feature forms a wedge-shaped depression that tapers from a maximum thickness of 17,000 feet on the western and southern margins to a zero edge along the northeast. Devon's properties in Canada range from shallow oil and natural gas production in northern Alberta to deep, long-lived gas reservoirs in the Foothills area near the Alberta/British Columbia border. Approximately 2.2 million net acres of undeveloped leasehold in the Western Canadian Sedimentary Basin provide Devon with numerous exploration and development opportunities.
INTERNATIONAL DIVISION PROPERTIES
Most of Devon's proved reserves that lie outside North America are located under the Caspian Sea, offshore Azerbaijan, part of the former Soviet Union. The Caspian Basin is considered to hold some of the world's last known major undeveloped hydrocarbon reserves. Devon holds a 4.8% carried interest in the Azeri-Chirag-Gunashli joint development area. This area is estimated to contain five billion barrels of crude oil. Devon expects significant production from its interest in Azerbaijan to begin sometime between 2005 and 2010. Devon also has international operations in Brazil, Egypt, Qatar and Venezuela. In Egypt, Devon expects to begin producing oil in the second half of 2000 from a 1999 discovery. Although Devon currently produces a modest amount of oil in Venezuela, we do not expect to remain active in that country.
TITLE TO PROPERTIES
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. Devon believes that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.
As is customary in the industry in the case of undeveloped properties, little investigation of record title is made at the time of acquisition (other than a preliminary review of local records). Investigations, generally including a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
ITEM 3. LEGAL PROCEEDINGS
Ramco Dispute
In October 1995, subsidiaries of Devon acquired in the PennzEnergy merger filed an action, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States District Court for the Southern District of Texas, Houston Division, against Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively "Ramco"). The underlying dispute involves Ramco's asserted claim to an interest in the Karabakh prospect, an oil and gas field located in the territorial waters of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the litigation, the operator of the Karabakh prospect determined that the hydrocarbon accumulation tested by three exploratory wells was not commercial. The federal suit sought to compel Ramco to arbitrate certain disputes that have arisen between it and
18

the Devon plaintiffs pursuant to the Federal Arbitration Act and the Convention on the Recognition and Enforcement of Foreign Arbitral Awards. After the filing of the federal action, the Devon plaintiffs filed an Original Petition for Declaration Relief in the 281st Judicial District Court of Harris County, Texas. The state suit, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is expressly conditioned upon a determination in the federal suit that the disputes between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a declaration that the Devon plaintiffs have not breached any agreements with Ramco, and do not owe and/or have not breached any fiduciary or other legal duty to Ramco including, without limitation, a duty of good faith and fair dealing. In November 1995, Ramco asserted a counterclaim in the state court action, asserting breach of contract and breach of fiduciary duties. The counterclaim seeks a declaratory judgment granting Ramco a participation interest in the Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees, court costs and other unspecified relief.
The judge in the federal suit granted in part the plaintiffs' motion to compel arbitration and ordered arbitration to be held in New York, New York. The United States Court of Appeals for the Fifth Circuit generally affirmed the ruling of the judge in the federal suit and the Devon plaintiffs initiated arbitration. The parties have been engaged in settlement discussions and the selection of arbitrators has been suspended by agreement of the parties pending the outcome of the settlement discussions.
Royalty Matters
More than 30 oil companies, including Devon as a result of the PennzEnergy merger, are involved in disputes in which it is alleged that the oil companies and related parties have underpaid holders of royalty interests, overriding royalty interests and working interests in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana. Certain parties to the federal litigation have entered into a global settlement agreement which provides for a conditional nationwide settlement, subject to opt-outs, of the crude oil royalty, overriding royalty and working interest claims of all members of the settlement class, including claims in the federal litigation and in numerous other individual and class action cases pending throughout the United States. The federal court held a fairness hearing April 5, 1999, and the settlement was approved. The Amended Final Judgment was entered September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon is a party to the settlement agreement, which explicitly refutes an admission of liability, but was entered into to avoid expensive and protracted litigation.
Also, pending is a separate suit in federal court in Texas alleging that more than 30 major oil companies, including Devon as a result of the PennzEnergy merger, underpaid royalties to the United States in connection with crude oil produced from United States owned and/or controlled lands since 1986. The claims were filed by private litigants under the federal False Claims Act, and after investigation, the United States served notice of its intent to intervene as to certain defendants. Devon has reached an agreement in principle with the United States and the private litigants to settle the claims made in the case. Devon believes that it has acted reasonably and paid royalties in good faith, but has entered into the settlement agreement, which explicitly refutes an admission of liability, to avoid expensive and protracted litigation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such settlement of the royalty matters.
19

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge as of March 24, 2000, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
20

PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET PRICE
Devon's common stock has been traded on the American Stock Exchange (the "AMEX") since September 29, 1988. Prior to September 29, 1988, Devon's common stock was privately held. Commencing on December 15, 1998, a new class of Devon exchangeable shares began trading on The Toronto Stock Exchange ("TSE") under the symbol NSX. These shares are essentially equivalent to Devon common stock. However, because they are issued by Devon's wholly-owned subsidiary, Northstar, they qualify as a domestic Canadian investment for Canadian institutional shareholders. They are exchangeable at any time, on a one-for-one basis, for common shares of Devon at the holder's option.
The following table sets forth the high and low sales prices for Devon common stock and exchangeable shares as reported by the AMEX and TSE for the periods indicated.

                                          American Stock Exchange           The Toronto Stock Exchange
                                       -----------------------------       -----------------------------
                                                             Average                             Average
                                       High      Low         Daily          High        Low      Daily
                                       (US$)     (US$)       Volume        (CN$)       (CN$)     Volume
                                       -----     -----      --------       ------      -----     -------
1998:
Quarter Ended March 31, 1998           41.13     32.88        90,867
Quarter Ended June 30, 1998            40.50     32.63        97,527
Quarter Ended September 30, 1998       36.63     26.13       158,909
Quarter Ended December 31, 1998 *      36.69     27.75       140,888        45.45      42.75       1,220
1999:
Quarter Ended March 31, 1999           31.75     20.13       233,954        48.00      30.40       4,240
Quarter Ended June 30, 1999            37.44     25.94       225,938        54.85      39.60      15,457
Quarter Ended September 30, 1999       44.94     33.00       624,356        65.75      51.30      11,650
Quarter Ended December 31, 1999        42.00     29.50       486,409        61.60      43.45       3,108
2000:
Quarter Ended March 31, 2000           45.25     31.69       380,690        65.25      45.65      13,493
(through March 15, 2000)	

* Trading of the exchangeable shares on the TSE commenced on December 15, 1998.
DIVIDENDS
Devon commenced the payment of regular quarterly cash dividends on its common stock on June 30, 1993, in the amount of $0.03 per share. Effective December 31, 1996, Devon increased its quarterly dividend payment to $0.05 per share. Devon anticipates continuing to pay regular quarterly dividends in the foreseeable future. Dividends are also paid on the exchangeable shares at the same rate and on the same dates as dividends paid on the common stock.
On March 15, 2000, there were 13,796 holders of record of Devon common stock and 48 holders of record for the exchangeable shares.
21

ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information (not covered by the independent auditors' reports) should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and the consolidated financial statements and the notes thereto included in "Item 8. Financial Statements and Supplementary Data." Note 2 to the consolidated financial statements included in Item 8 of this report contains information on the 1999 merger with PennzEnergy and the 1998 combination of Devon and Northstar, as well as unaudited pro forma financial data for the years 1999 and 1998.

                                                                            YEAR ENDED DECEMBER 31,
                                                            ------------------------------------------------------------
                                                              1999         1998         1997         1996        1995
                                                            ---------    ---------    ---------    ---------   ---------
                                                                    (THOUSANDS, EXCEPT PER SHARE DATA AND RATIOS)
OPERATING RESULTS
    Oil sales                                               $ 273,234      143,624      207,725      136,023     115,606
    Gas sales                                                 385,925      209,344      219,459      101,443      71,194
    NGLs sales                                                 56,344       16,692       24,920       19,299       9,091
    Other revenue                                              18,996       17,848       47,555       34,570      14,252
                                                            ---------    ---------    ---------    ---------   ---------
    Total revenues                                            734,499      387,508      499,659      291,335     210,143
                                                            ---------    ---------    ---------    ---------   ---------

    Lease operating expenses                                  166,848      113,484      100,897       58,734      51,724
    Production taxes                                           23,055       13,916       19,227       10,880       7,052
    Depreciation, depletion and amortization
          of property and equipment                           254,275      123,844      169,108       70,307      73,440
    Amortization of goodwill                                   16,111           --           --           --          --
    General and administrative expenses                        53,845       23,554       24,381       15,111      14,906
    Northstar Combination expenses                                 --       13,149           --           --          --
    Interest expense                                           66,913       22,632       18,788       12,662      10,885
    Deferred effect of changes in foreign currency
        exchange rate on subsidiary's long-term
        debt                                                  (13,154)      16,104        5,860          199         307
    Distributions on preferred securities of
        subsidiary trust                                        6,884        9,717        9,717        4,753          --
    Reduction of carrying value of oil and
        gas properties                                             --      126,900      625,514           --      97,061
                                                            ---------    ---------    ---------    ---------   ---------
    Total costs and expenses                                  574,777      463,300      973,492      172,646     255,375
                                                            ---------    ---------    ---------    ---------   ---------

    Earnings (loss) before income taxes                       159,722      (75,792)    (473,833)     118,689     (45,232)
    Income tax expense (benefit):
        Current                                                24,656        7,687       26,857        7,834       5,292
        Deferred                                               40,510      (23,194)    (200,699)      43,252     (24,631)
                                                            ---------    ---------    ---------    ---------   ---------
        Total                                                  65,166      (15,507)    (173,842)      51,086     (19,339)
                                                            ---------    ---------    ---------    ---------   ---------

    Net earnings (loss)                                     $  94,556      (60,285)    (299,991)      67,603     (25,893)
                                                            =========    =========    =========    =========   =========

    Net earnings (loss) applicable to common
        stock                                               $  90,905      (60,285)    (299,991)      67,603     (25,893)
                                                            =========    =========    =========    =========   =========

    Net earnings (loss) per share:
        Basic                                               $    1.51        (1.25)       (6.38)        2.06       (0.80)
        Diluted                                             $    1.46        (1.25)       (6.38)        1.99       (0.80)

    Cash dividends per common share(1)                      $    0.20         0.15         0.14         0.15        0.14
    Weighted average common shares
      outstanding - basic                                      60,015       48,376       47,040       32,812      32,473
    Ratio of earnings to combined fixed charges
       and preferred stock dividends(2)                          3.37          N/A          N/A         7.59         N/A	

22

                                                                               DECEMBER 31,
                                                      -------------------------------------------------------------
                                                        1999         1998         1997         1996         1995
                                                      ----------   ---------    ---------    ---------    ---------
                                                                           (THOUSANDS)
BALANCE SHEET DATA
Total assets                                          $4,623,160   1,226,356    1,248,986    1,183,290      715,510
Debentures exchangeable into shares of
    Chevron Corporation common stock                  $  760,313          --           --           --           --
Other long-term debt                                  $1,026,808     405,271      305,337       83,000      220,137
Convertible preferred securities of
     subsidiary trust                                 $       --     149,500      149,500      149,500           --
Stockholders' equity                                  $2,025,520     522,963      596,546      678,772      394,647	

                                                                          YEAR ENDED DECEMBER 31,
                                                      -------------------------------------------------------------
                                                        1999         1998         1997         1996         1995
                                                      ---------    ---------    ---------    ---------    ---------
                                                                      (THOUSANDS, EXCEPT PER UNIT DATA)
CASH FLOW DATA
    Net cash provided by operating activities         $ 205,628      191,571      235,056      144,248      122,136
    Net cash used in investing activities             $(253,717)    (271,960)    (147,583)    (243,451)    (251,571)
    Net cash provided by (used in) financing
      activities                                      $ 195,398       57,618      (77,141)      96,420      125,312
    Modified EBITDA(3,5)                              $ 490,751      223,405      355,154      206,610      136,461
    Cash margin(4,5)                                  $ 392,298      183,369      299,792      181,361      120,284

PRODUCTION, PRICE AND OTHER DATA
    Production:
        Oil (MBbls)                                      15,416       11,903       11,783        6,780        7,130
        Gas (MMcf)                                      198,457      133,065      121,810       62,186       58,234
        NGLs (MBbls)                                      4,022        1,939        1,891        1,255          831
        MBoe(6)                                          52,514       36,020       33,976       18,399       17,666
    Average prices:
        Oil (Per Bbl)                                 $   17.72        12.07        17.63        20.06        16.21
        Gas (Per Mcf)                                 $    1.94         1.57         1.80         1.63         1.22
        NGLs (Per Bbl)                                $   14.01         8.61        13.18        15.38        10.94
        Per Boe(6)                                    $   13.62        10.26        13.31        13.96        11.09
    Costs per Boe:
        Operating costs                               $    3.62         3.54         3.54         3.78         3.33
        Depreciation, depletion and amortization
          of oil and gas properties                   $    4.65         3.32         4.86         3.69         4.04
        General and administrative expenses           $    1.03         0.65         0.72         0.82         0.84	

(1) Cash dividends per share are presented based on the combined amount of dividends paid by both Devon and Northstar in each year. The dividends per share are also based on the number of shares outstanding in each year assuming the Northstar Combination had been consummated as of the beginning of the earliest year presented. Northstar did not pay any dividends in 1997, or in 1998 prior to the closing of the Northstar Combination. Also, Northstar's dividends paid in 1996 and 1995 were at rates per share that were different from the rates paid by Devon in those years. Because of these facts, the cash dividends per share presented for 1995 through 1998 are not representative of the actual amounts paid by Devon on an historical basis. For the years 1998, 1997, 1996 and 1995, Devon's historical cash dividends per share were $0.20, $0.20, $0.14 and $0.12, respectively.
(2) For purposes of calculating the ratio of earnings to combined fixed charges and preferred stock dividends, (i) earnings consist of earnings before income taxes, plus fixed charges; (ii) fixed charges consist of interest expense, deferred effect of changes in foreign currency exchange rate on long-term debt, distributions on preferred securities of subsidiary trust, amortization of costs relating to indebtedness and the preferred securities of subsidiary trust, and one-third of rental
23

expense estimated to be attributable to interest; and (iii) preferred stock dividends consist of the amount of pre-tax earnings required to pay dividends on the outstanding preferred stock. For the years 1998, 1997 and 1995, earnings were insufficient to cover fixed charges by $75.8 million, $473.8 million and $45.2 million, respectively.
(3) Modified EBITDA represents earnings before interest (including deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt, and distributions on preferred securities of subsidiary trust), taxes, depreciation, depletion and amortization and reduction of carrying value of oil and gas properties.
(4) "Cash margin" equals total revenues less cash expenses. Cash expenses are all expenses other than the non-cash expenses of depreciation, depletion and amortization, deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt, reduction of carrying value of oil and gas properties and deferred income tax expense. Cash margin measures the net cash which is generated by a company's operations during a given period, without regard to the period such cash is actually physically received or spent by the company. This margin ignores the non-operational effect on a company's "net cash provided by operating activities", as measured by generally accepted accounting principles, from a company's activities as an operator of oil and gas wells. Such activities produce net increases or decreases in temporary cash funds held by the operator which have no effect on net earnings of the company.
(5) Modified EBITDA is presented because it is commonly accepted in the oil and gas industry as a financial indicator of a company's ability to service or incur debt. Cash margin is presented because it is commonly accepted in the oil and gas industry as a financial indicator of a company's ability to fund capital expenditures or service debt. Modified EBITDA and cash margin are also presented because investors routinely request such information. Management interprets the trends of modified EBITDA and cash margin in a similar manner as trends in net earnings.
Modified EBITDA and cash margin should be used as supplements to, and not as substitutes for, net earnings and net cash provided by operating activities determined in accordance with generally accepted accounting principles as measures of Devon's profitability or liquidity. There may be operational or financial demands and requirements that reduce management's discretion over the use of modified EBITDA and cash margin. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." Modified EBITDA and cash margin may not be comparable to similarly titled measures used by other companies.
(6) Gas volumes are converted to Boe or MBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not necessarily indicative of the relationship of oil and gas prices. The respective prices of oil, gas and NGLs are affected by market and other factors in addition to relative energy content.
24

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis addresses changes in Devon's financial condition and results of operations during the three year period of 1997 through 1999. Reference is made to "Item 6. Selected Financial Data" and "Item 8. Financial Statements and Supplementary Data."
OVERVIEW
On August 17, 1999, Devon and PennzEnergy Company ("PennzEnergy") closed their merger that was previously announced on May 20, 1999. In the merger, Devon issued approximately 21.5 million shares of common stock and assumed $1.6 billion of long-term debt and $0.7 billion of other liabilities. The merger added 396 million Boe of reserves, 13 million net acres of undeveloped leasehold and $3.2 billion of assets to Devon's balance sheet. This significantly expanded the scope of Devon's operations and moved Devon into the top ten of all U.S.-based independent oil and gas producers.
The PennzEnergy merger was accounted for under the purchase method of accounting for business combinations. Therefore, Devon's 1999 results do not include any effect of PennzEnergy's operations prior to August 17, 1999.
The PennzEnergy merger was completed less than a year after Devon's merger with Northstar Energy Corporation ("Northstar"). The December 10, 1998, combination of Devon and Northstar (the "Northstar Combination") added 115 million Boe of proved reserves and 1.8 million undeveloped acres, all in Canada. The Northstar Combination was accounted for under the pooling-of-interests method of accounting for business combinations. Accordingly, Devon's results for 1998 and prior years include the results of both Devon and Northstar as if the two had always been combined.
In addition to the two mergers, Devon's exploration, drilling and development efforts have also been significant contributors to Devon's growth over the last three years. Excluding the pooled results of Northstar prior to December 1998, Devon has spent approximately $492 million in its exploration, drilling and development efforts from 1997 through 1999. These costs included drilling 1,154 wells, of which 1,065 were completed as producers.
The impact of the mergers and drilling activities include the following changes from 1997 to 1999. (The following changes are calculated using 1997's results without combining Northstar's results, and the 1999 results include the effects of the added PennzEnergy operations for only the last 4 1/2 months of the year.)
o Combined oil, gas and NGLs production increased 32.3 million Boe, or 160%.
o Combined oil, gas and NGLs revenues increased $409.8 million, or 134%, during a period when the average combined price of oil, gas and NGLs fell by $1.53 per Boe, or 10%.
o Net cash provided by operating activities increased $36.9 million, or 22%. Cash margin increased $210.9 million, or 116%.
25

o Net earnings increased $19.3 million, or 26%.
o Production and operating expenses per Boe dropped $0.52 per Boe, or 19%.
o Depreciation, depletion and amortization of oil and gas properties per Boe increased $0.58 per Boe, or 14%.
o General and administrative expenses per Boe increased $0.39 per Boe, or 61%. However, Devon expects to eliminate a substantial part of this increase in costs per Boe in 2000 due to the termination at the end of 1999 of certain commitments inherited as part of the PennzEnergy merger.
During 1999, Devon marked its eleventh anniversary as a public company. While Devon has consistently increased production over this eleven-year period, volatility in oil and gas prices has resulted in considerable variability in earnings and cash flows. Prices for oil, natural gas and NGLs are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and world-wide economic growth, weather and other factors that are beyond Devon's control. Devon's future earnings and cash flows will continue to depend on market conditions.
Like all oil and gas production companies, Devon faces the challenge of natural production decline. As virgin pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas production company depletes part of its asset base with each unit of oil or gas it produces. Historically, Devon has been able to overcome this natural decline by adding, through drilling and acquisitions, more reserves than it produces. Devon's future growth, if any, will depend on its ability to continue to add reserves in excess of production.
Because oil and gas prices are influenced by many factors outside of its control, Devon's management has focused its efforts on increasing oil and gas reserves and production and controlling expenses. Over its eleven year history as a public company, Devon has been able to significantly reduce its operating costs per unit of production. Devon's future earnings and cash flows are dependent on its ability to continue to contain operating costs at levels that allow for profitable production of its oil and gas reserves.
RESULTS OF OPERATIONS
Devon's total revenues have risen from $499.7 million in 1997 to $734.5 million in 1999. In each of these three years, oil, gas and NGLs sales accounted for over 90% of total revenues.
Changes in oil, gas and NGLs production, prices and revenues from 1997 to 1999 are shown in the following tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)
26

                                                                      TOTAL
                                       -------------------------------------------------------------
                                                              YEAR ENDED DECEMBER 31,
                                       -------------------------------------------------------------
                                                         1999                      1998
                                          1999          VS 1998    1998           VS 1997     1997
                                       ----------       -------  ---------        -------   --------
                                                        (ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
  Oil (MBbls) ......................       15,416         +30%      11,903          +1%       11,783
  Gas (MMcf) .......................      198,457         +49%     133,065          +9%      121,810
  NGLs (MBbls) .....................        4,022        +107%       1,939          +3%        1,891
  Oil, gas and NGLs (MBoe) .........       52,514         +46%      36,020          +6%       33,976

REVENUES
  Per Unit of Production:
    Oil (per Bbl) ..................   $    17.72         +47%       12.07         (32)%        17.63
    Gas (per Mcf) ..................   $     1.94         +24%        1.57         (13)%         1.80
    NGLs (per Bbl) .................   $    14.01         +63%        8.61         (35)%        13.18
    Oil, gas and NGLs (per Boe) ....   $    13.62         +33%       10.26         (23)%        13.31

  Absolute:
    Oil ............................   $  273,234         +90%     143,624         (31)%      207,725
    Gas ............................   $  385,925         +84%     209,344          (5)%      219,459
    NGLs ...........................   $   56,344        +238%      16,692         (33)%       24,920
                                       ----------                ---------                  ---------
    Oil, gas and NGLs ..............   $  715,503         +94%     369,660         (18)%      452,104
                                       ==========                =========                  =========	

                                                                    DOMESTIC
                                       --------------------------------------------------------------
                                                              YEAR ENDED DECEMBER 31,
                                       --------------------------------------------------------------
                                                         1999                       1998
                                          1999          VS 1998     1998           VS 1997     1997
                                       ----------       -------   ---------        -------   --------
                                                        (ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
  Oil (MBbls) ......................        9,791         +73%        5,646           (7)%      6,055
  Gas (MMcf) .......................      124,896         +90%       65,907           +8 %     61,015
  NGLs (MBbls) .....................        3,322        +142%        1,373           (6)%      1,468
  Oil, gas and NGLs (MBoe) .........       33,929         +88%       18,004           +2 %     17,692

REVENUES
  Per Unit of Production:
    Oil (per Bbl) ..................   $    19.83         +59%        12.45          (35)%      19.08
    Gas (per Mcf) ..................   $     2.23         +16%         1.92          (16)%       2.28
    NGLs (per Bbl) .................   $    13.94         +59%         8.79          (33)%      13.18
    Oil, gas and NGLs (per Boe) ....   $    15.31         +32%        11.59          (25)%      15.48

  Absolute:
    Oil ............................   $  194,162        +176%       70,286          (39)%    115,504
    Gas ............................   $  279,030        +121%      126,273           (9)%    139,018
    NGLs ...........................   $   46,310        +284%       12,071          (38)%     19,338
                                       ----------                 ---------                  --------
    Oil, gas and NGLs ..............   $  519,502        +149%      208,630          (24)%    273,860
                                       ==========                 =========                  ========	

27

                                                                  CANADA
                                       ------------------------------------------------------------
                                                              YEAR ENDED DECEMBER 31,
                                       ------------------------------------------------------------
                                                         1999                   1998
                                          1999          VS 1998     1998       VS 1997      1997
                                       ----------       -------   ---------   ---------   ---------
                                                        (ABSOLUTE AMOUNTS IN THOUSANDS)
PRODUCTION
  Oil (MBbls) ......................        5,178         (17)%       6,257      + 9 %        5,728
  Gas (MMcf) .......................       73,561         +10%       67,158      +10 %       60,795
  NGLs (MBbls) .....................          700         +24%          566      +34 %          423
  Oil, gas and NGLs (MBoe) .........       18,138          +1%       18,016      +11 %       16,284

REVENUES
  Per Unit of Production:
    Oil (per Bbl) ..................   $    14.71         +26%        11.72      (27)%        16.10
    Gas (per Mcf) ..................   $     1.45         +17%         1.24       (6)%         1.32
    NGLs (per Bbl) .................   $    14.33         +76%         8.16      (38)%        13.20
    Oil, gas and NGLs (per Boe) ....   $    10.65         +19%         8.94      (18)%        10.95

  Absolute:
    Oil ............................   $   76,171          +4%       73,338      (20)%       92,221
    Gas ............................   $  106,895         +29%       83,071       +3 %       80,441
    NGLs ...........................   $   10,034        +117%        4,621      (17)%        5,582
                                       ----------                 ---------               ---------
    Oil, gas and NGLs ..............   $  193,100         +20%      161,030      (10)%      178,244
                                       ==========                 =========               =========	

In addition to the volumes included in the prior tables for domestic and Canadian production, in the last 4 1/2 months of 1999 Devon also produced 424,000 barrels of oil in Venezuela and 23,000 barrels of oil in Azerbaijan. The oil revenues generated by this production were $2.9 million. This production was added by the PennzEnergy merger.
OIL REVENUES 1999 vs. 1998 Oil revenues increased $129.6 million in 1999. Oil revenues increased $87.2 million due to a $5.65 per barrel increase in the average price of oil in 1999. An increase in 1999's production of 3.5 million barrels caused oil revenues to increase by $42.4 million. The PennzEnergy merger added 5.3 million barrels of production during the last 4 1/2 months of 1999. This increase was partially offset by a 1.8 million barrel decline in 1999 production from Devon's other properties. The disposition of certain Canadian producing properties during 1998, the deferral of some oil-oriented projects, natural decline, and the effect of some properties that were shut-in earlier in 1999 due to low prices were the primary reasons for this production decline.
1998 vs. 1997 Oil revenues decreased $64.1 million in 1998. An average price decline of $5.56 per barrel reduced revenues by $66.2 million. This was slightly offset by $2.1 million of revenues added by production gains of 120,000 barrels.
GAS REVENUES 1999 vs. 1998 Gas revenues increased $176.6 million in 1999. A 65.4 Bcf increase in production in 1999 added $102.9 million of gas revenues compared to 1998. A $0.37 per Mcf increase in the average gas price in 1999, contributed $73.7 million of the increase in gas revenues.
The largest contributor to the 1999 production increase was production added by the PennzEnergy merger. The PennzEnergy properties added 55.5 Bcf of production during the 4 1/2 months following the merger. A 6.4 Bcf increase in Devon's Canadian gas production also
28

contributed to the increase in 1999 gas production. The Canadian gas production increase was primarily the result of two 1998 acquisitions.
Gas production from Devon's historical domestic properties also increased in 1999. This was due to a 3.9 Bcf increase in production from Devon's San Juan Basin coal seam gas properties. These properties produced 23.8 Bcf of gas in 1999 compared to 19.9 Bcf in 1998. This increase was largely the result of a program of mechanical improvements implemented at the Northeast Blanco Unit coal seam gas property during 1998.
1998 vs. 1997 Gas revenues decreased $10.1 million in 1998. An average price decline of $0.23 per Mcf reduced revenues by $30.4 million. This was partially offset by higher production in 1998. A production increase of 11.3 Bcf in 1998 added gas revenues of $20.3 million.
The San Juan Basin coal seam gas properties produced 19.9 Bcf in 1998 compared to 17.6 Bcf in 1997. The majority of the production gains realized in 1998 were the result of improvements at the Northeast Blanco Unit property.
NGLS REVENUES 1999 vs. 1998 NGLs revenues increased $39.7 million in 1999. An increase in 1999's average price of $5.40 per barrel caused NGLs revenues to increase $21.7 million. A production increase of 2.1 million barrels in 1999 caused revenues to increase $18.0 million. Production from the PennzEnergy properties for the last 4 1/2 months of 1999 accounted for 1.7 million barrels of the 1999 increase.
1998 vs. 1997 NGLs revenues decreased $8.2 million in 1998. An average price decline of $4.57 per barrel caused revenues to drop by $8.9 million. This decline was slightly offset by production increases of 48,000 barrels. Such production gains added $0.7 million of revenues in 1998.
OTHER REVENUES 1999 vs. 1998 Other revenues increased $1.1 million in 1999. Other revenues in 1999 included $6.7 million of dividend income in the last 4 1/2 months of the year from the 7.1 million shares of Chevron Corporation common stock acquired by Devon in the PennzEnergy merger. This dividend income, along with increases in 1999's revenues from third-party gas processing activities and interest income, caused other revenues to increase by $9.9 million. These increases were partially offset by $8.8 million of one-time revenues recognized by Northstar in 1998 from terminations of certain management agreements and gas contracts.
1998 vs. 1997 Other revenues decreased $29.7 million in 1998. This decrease was primarily due to Northstar's $29.4 million of gains from asset sales in 1997 which did not recur in 1998.
29

EXPENSES The details of the changes in pre-tax expenses between 1997 and 1999 are shown in the table below.

                                                                           YEAR ENDED DECEMBER 31,
                                                           ------------------------------------------------------
                                                                         1999                   1998
                                                              1999      VS 1998     1998       VS 1997      1997
                                                           ----------   -------   ---------   ---------   -------
                                                                       (ABSOLUTE AMOUNTS IN THOUSANDS)
Absolute:
  Production and operating expenses:
    Lease operating expenses ............................  $  166,848     +47%    113,484        +12%     100,897
    Production taxes ....................................      23,055     +66%     13,916       (28)%      19,227
  Depreciation, depletion and amortization of
    oil and gas properties ..............................     244,517    +104%    119,719       (27)%     164,977
   Amortization of goodwill .............................      16,111      N/A         --          --          --
                                                           ----------            --------                --------
      Subtotal ..........................................     450,531     +82%    247,119        -13%     285,101

  Depreciation and amortization of non-oil and
    gas properties ......................................       9,758    +137%      4,125          --       4,131
  General and administrative expenses ...................      53,845    +129%     23,554        (3)%      24,381
  Northstar Combination expenses ........................          --   (100)%     13,149         N/A          --
  Interest expense ......................................      66,913    +196%     22,632        +20%      18,788
  Deferred effect of changes in foreign currency
    exchange rate on subsidiary's long-term debt ........     (13,154)     N/A     16,104       +175%       5,860
  Distributions on preferred securities of
    subsidiary trust ....................................       6,884    (29)%      9,717          --       9,717
  Reduction of carrying value of oil and gas
    properties ..........................................          --   (100)%    126,900       (80)%     625,514
                                                           ----------            --------                --------

      Total .............................................  $  574,777     +24%    463,300       (52)%     973,492
                                                           ==========            ========                ========

Per Boe:
  Production and operating expenses:
    Lease operating expenses ............................  $     3.18      +1%       3.15         +6%        2.97
    Production taxes ....................................        0.44     +13%       0.39       (32)%        0.57
  Depreciation, depletion and amortization of
    oil and gas properties ..............................        4.65     +40%       3.32       (32)%        4.86
  Amortization of goodwill ..............................        0.31      N/A         --          --          --
                                                           ----------            --------               ---------
      Subtotal ..........................................        8.58     +25%       6.86       (18)%        8.40

  Depreciation and amortization of non-oil and
    gas properties (1) ..................................        0.19     +58%       0.12          --        0.12
  General and administrative expenses (1) ...............        1.03     +58%       0.65       (10)%        0.72
  Northstar Combination expenses (1) ....................          --   (100)%       0.36         N/A          --
  Interest expense (1) ..................................        1.27    +102%       0.63        +15%        0.55
  Deferred effect of changes in foreign currency
    exchange rate on subsidiary's long-term debt (1) ....       (0.25)     N/A       0.45       +165%        0.17
  Distributions on preferred securities of
    subsidiary trust (1) ................................        0.13    (52)%      0.27         (4)%        0.28
  Reduction of carrying value of oil and gas
    properties (1) ......................................          --   (100)%      3.52        (81)%       18.41
                                                           ----------          ---------                ---------
     Total ..............................................  $    10.95    (15)%     12.86        (55)%       28.65
                                                           ==========          =========                =========	

(1) Though per Boe amounts for these expense items may be helpful for profitability trend analysis, these expenses are not directly attributable to production volumes.

30

PRODUCTION AND OPERATING EXPENSES The details of the changes in production and operating expenses between 1997 and 1999 are shown in the table below.

                                                                                        TOTAL
                                                 --------------------------------------------------------------------------
                                                                                YEAR ENDED DECEMBER 31,
                                                 --------------------------------------------------------------------------
                                                                    1999                           1998
                                                    1999          VS 1998          1998           VS 1997          1997
                                                 ------------   ------------   ------------     ------------   ------------
                                                                      (ABSOLUTE AMOUNTS IN THOUSANDS)
Absolute:
  Recurring lease operating expenses             $    160,166       +49%            107,554         +11%             96,738
  Well workover expenses                                6,682       +13%              5,930         +43%              4,159
  Production taxes                                     23,055       +66%             13,916        (28)%             19,227
                                                 ------------                  ------------                    ------------
     Total production and operating expenses     $    189,903       +49%            127,400          +6%            120,124
                                                 ============                  ============                    ============

Per Boe:
  Recurring lease operating expenses             $       3.05        +2%               2.99          +5%               2.85
  Well workover expenses                                 0.13      (19)%               0.16         +33%               0.12
  Production taxes                                       0.44       +13%               0.39        (32)%               0.57
                                                 ------------                  ------------                    ------------
     Total production and operating expenses     $       3.62        +2%               3.54           --               3.54
                                                 ============                  ============                    ============	

                                                                                 DOMESTIC
                                                                          YEAR ENDED DECEMBER 31,
                                                 --------------------------------------------------------------------------
                                                                    1999                           1998
                                                     1999          VS 1998         1998           VS 1997         1997
                                                 ------------   ------------   ------------     ------------   ------------
                                                                      (ABSOLUTE AMOUNTS IN THOUSANDS)
Absolute:
  Recurring lease operating expenses             $    109,775       +80%             60,920         +11%             54,969
  Well workover expenses                                5,742       +23%              4,654         +48%              3,143
  Production taxes                                     21,692       +77%             12,255        (31)%             17,646
                                                 ------------                  ------------                    ------------
     Total production and operating expenses     $    137,209       +76%             77,829          +3%             75,758
                                                 ============                  ============                    ============

Per Boe:
  Recurring lease operating expenses             $       3.23       (4)%               3.38          +9%               3.10
  Well workover expenses                                 0.17      (35)%               0.26         +44%               0.18
  Production taxes                                       0.64       (6)%               0.68        (32)%               1.00
                                                 ------------                  ------------                    ------------
     Total production and operating expenses     $       4.04       (6)%               4.32          +1%               4.28
                                                 ============                  ============                    ============	

                                                                                  CANADA
                                                 --------------------------------------------------------------------------
                                                                          YEAR ENDED DECEMBER 31,
                                                 --------------------------------------------------------------------------
                                                                    1999                          1998
                                                     1999          VS 1998        1998            VS 1997          1997
                                                 ------------   ------------   ------------     ------------   ------------
                                                                      (ABSOLUTE AMOUNTS IN THOUSANDS)
Absolute:
  Recurring lease operating expenses             $     48,891        +5%             46,634         +12%             41,769
  Well workover expenses                                  940      (26)%              1,276         +26%              1,016
  Production taxes                                      1,363      (18)%              1,661          +5%              1,581
                                                 ------------                  ------------                    ------------
     Total production and operating expenses     $     51,194        +3%             49,571         +12%             44,366
                                                 ============                  ============                    ============

Per Boe:
  Recurring lease operating expenses             $       2.70        +4%               2.59          +1%               2.56
  Well workover expenses                                 0.05      (29)%               0.07         +17%               0.06
  Production taxes                                       0.07      (22)%               0.09        (10)%               0.10
                                                 ------------                  ------------                    ------------
     Total production and operating expenses     $       2.82        +3%               2.75          +1%               2.72
                                                 ============                  ============                    ============	

31

In addition to the expenses included in the prior tables for domestic and Canadian operations, in the last 4 1/2 months of 1999 Devon also incurred $1.5 million of recurring lease operating expenses on its properties outside North America. These expenses were related to properties added by the PennzEnergy merger.
1999 vs. 1998 Recurring lease operating expenses increased $52.6 million in 1999. Domestic expenses increased $48.9 million in 1999 due to $55.8 million of expenses for the last 4 1/2 months of the year from the PennzEnergy properties. Other than the added costs from the PennzEnergy properties, recurring expenses on Devon's other domestic properties dropped $6.9 million in 1999. Efficiencies achieved in certain of Devon's oil producing properties contributed most of this cost reduction.
The majority of Devon's production taxes are assessed on its onshore domestic properties. In the U.S., most of the production taxes paid are based on a fixed percentage of revenues. Therefore, the 149% increase in domestic oil, gas and NGLs revenues was the primary cause of the 77% increase in domestic production taxes. Production taxes did not increase proportionately to the increase in revenues. This was primarily due to the addition in 1999 of gas revenues from offshore Gulf of Mexico properties acquired in the PennzEnergy merger. Revenues generated from such offshore properties do not incur state production taxes.
1998 vs. 1997 Recurring lease operating expenses increased $10.8 million, or 11%, in 1998. The primary causes of this increase were the addition of wells drilled or acquired during 1998 and the effect of having a full year of operations in 1998 from certain Canadian properties acquired in March 1997.
Recurring expenses increased $0.14 per Boe, or 5%, in 1998. This increase was predominantly caused by a 9% increase in costs per Boe on the domestic properties. The operating expenses of the domestic wells drilled during the year raised the overall average costs per Boe in the U.S.
As previously stated, most of the U.S. production taxes paid are based on a fixed percentage of revenues. Therefore, the 24% drop in 1998 domestic oil, gas and NGLs revenues was the primary cause of the 31% decrease in domestic production taxes.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") Devon's largest recurring non-cash expense is DD&A. DD&A of oil and gas properties is calculated as the percentage of total proved reserve volumes produced during the year, multiplied by the net capitalized investment in those reserves including estimated future development costs (the "depletable base"). Generally, if reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.
1999 vs. 1998 Oil and gas property related DD&A increased $124.8 million, or 104%, in 1999. An increase in the consolidated DD&A rate from $3.32 per Boe in 1998 to $4.65 per Boe in 1999 caused DD&A expense to increase $70.0 million. The 1999 rate of $4.65 per Boe was a
32

blended rate of before and after the PennzEnergy merger. The consolidated rate going into 2000 was $5.41 per Boe. Oil and gas property related DD&A expense increased $54.8 million due to the 46% increase in oil, gas and NGLs production in 1999.
Non-oil and gas property DD&A increased $5.6 million in 1999 compared to 1998. Depreciation of the non-oil and gas properties acquired in the PennzEnergy merger and depreciation of Devon's new Wyoming gas pipeline and gathering system, accounted for the increase in 1999's expense.
1998 vs. 1997 Oil and gas property related DD&A decreased $45.3 million, or 27%, in 1998. A 32% drop in the consolidated DD&A rate per Boe from $4.86 in 1997 to $3.32 in 1998 reduced 1998's DD&A expense by $55.2 million. This decrease was partially offset by $9.9 million of increased expense caused by the 6% increase in combined oil, gas and NGLs production in 1998. The $625.5 million reduction in the carrying value of Canadian oil and gas properties recorded at the end of 1997 was the primary cause of the drop in the 1998 DD&A rate.
AMORTIZATION OF GOODWILL In connection with the PennzEnergy merger, Devon recorded $338.9 million of goodwill. The goodwill recorded was allocated $302.0 million to domestic properties and $26.9 million to international properties. The goodwill is being amortized using the units-of-production method. Substantially all of the $16.1 million of amortization recognized in 1999 was related to the domestic balance.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A capitalized pursuant to the full cost method of accounting. The other is the amount of G&A reimbursed by working interest owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and operational stages of a property's life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the consolidated statements of operations. See following table for a summary of G&A expenses by component.

                                                                    TOTAL
                                            ----------------------------------------------------
                                                           YEAR ENDED DECEMBER 31,
                                            ----------------------------------------------------
                                                         1999                  1998
                                              1999     VS 1998    1998        VS 1997       1997
                                            -------    -------  -------       -------    -------
                                                                   (IN THOUSANDS)
Gross G&A  ...........................      $94,341      +85%    50,989          +7%       47,832
Capitalized G&A.......................      (18,678)     +94%    (9,612)        +27%       (7,575)
Reimbursed G&A........................      (21,818)     +22%   (17,823)        +12%      (15,876)
                                            -------              ------                   -------
    Net G&A...........................      $53,845     +129%    23,554         (3)%       24,381
                                            =======              ======                   =======	

1999 vs. 1998 Net G&A increased $30.3 million in 1999. Gross G&A increased $43.4 million in 1999. Included in the increase in gross expenses were $36.7 million of expenses related to 4 1/2 months of the PennzEnergy operations. The PennzEnergy amounts included $4.4 million of nonrecurring retention bonuses paid to certain PennzEnergy employees as an inducement to remain with Devon for two months following the merger closing.
33

G&A was lowered $9.1 million due to an increase in the amount capitalized as part of oil and gas properties. The 1999 amount capitalized included $5.5 million related to the PennzEnergy operations for the last 4 1/2 months of the year. G&A was also reduced by a $4.0 million increase in the amount of reimbursements on operated properties. The 1999 reimbursements received from the PennzEnergy properties were $6.0 million.
1998 vs. 1997 Net G&A decreased $0.8 million in 1998. Gross G&A increased $3.1 million in 1998. However, this increase was more than offset by increases in the amount of G&A capitalized and reimbursed in 1998. G&A was lowered $2.0 million due to an increase in the amount capitalized as part of oil and gas properties. G&A was also reduced by a $1.9 million increase in the amount of reimbursements on operated properties.
NORTHSTAR COMBINATION EXPENSES Approximately $13.1 million of expenses were incurred in 1998 in connection with the Northstar Combination. These expenses consisted primarily of investment bankers' fees, legal fees and costs of printing and distributing the proxy statement to shareholders. The pooling-of-interests method of accounting for business combinations requires such costs to be expensed as opposed to capitalized as costs of the transaction.
INTEREST EXPENSE 1999 vs. 1998 Interest expense increased $44.3 million in 1999. An increase in the average debt balance outstanding from $324.7 million in 1998 to $988.1 million in 1999 caused interest expense to increase by $43.5 million. The average interest rate on outstanding debt decreased slightly from 6.7% in 1998 to 6.6% in 1999. This rate decrease caused interest expense to decrease $0.5 million in 1999. Other items included in interest expense that are not related to the debt balance outstanding, such as facility and agency fees, amortization of costs and other miscellaneous items, were $1.3 million higher in 1999 compared to 1998.
The increase in the average debt balance in 1999 was attributable to the long-term debt assumed in the PennzEnergy merger on August 17, 1999. At that date, Devon assumed $1.6 billion of long-term debt with a weighted average interest rate of 7.2%. In the fourth quarter 1999, Devon retired $350 million of the assumed debt with a portion of the $402 million of net proceeds received from the issuance of 10.3 million shares of Devon common stock.
1998 vs. 1997 Interest expense increased $3.8 million, or 20%, in 1998. The average interest rate increased from 5.4% in 1997 to 6.7% in 1998. The increase in the average rate was primarily due to the fact that Northstar replaced a large portion of its floating-rate debt with longer term, fixed-rate debt early in 1998. The increase in 1998's average rate caused a $4.4 million increase in interest expense. The average debt balance increased from $267.0 million in 1997 to $324.7 million in 1998. This increase in the debt outstanding caused interest expense to increase $3.1 million. The increases caused by higher rates and higher balances outstanding were partially offset by the fact that 1997's interest expense included a $3.3 million "make-whole" payment related to the early retirement of debt. Other items included in interest expense that are not related to the balance of debt outstanding, such as facility and agency fees, amortization of costs and other miscellaneous items, were $0.4 million lower in 1998 compared to 1997.
DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT Prior to January 2000, Northstar had certain fixed rate senior notes which were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the
34

Canadian dollar from the dates the notes were issued to the dates of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate changes. In mid-January 2000, the U.S. dollar denominated notes were retired prior to maturity with cash on hand and borrowings under Devon's long-term credit facilities.
1999 vs. 1998 The rate of converting Canadian dollars to U.S. dollars increased from $0.6535 at the end of 1998 to $0.6929 at the end of 1999. The balance of Northstar's U.S. dollar denominated notes remained constant at $225 million throughout 1999. The higher conversion rate on the $225 million of debt reduced the Canadian dollar equivalent of debt recorded by Northstar at the end of 1999. Therefore, a $13.2 million reduction to expenses was recorded in 1999.
1998 vs. 1997 The principal balance of Northstar's U.S. dollar denominated notes increased from $135 million at the end of 1997 to $225 million at the end of 1998. The rate of converting Canadian dollars to U.S. dollars decreased from $0.6997 at the end of 1997 to $0.6535 at the end of 1998. The combination of these factors caused $16.1 million to be recorded as an expense in 1998.
DISTRIBUTIONS ON PREFERRED SECURITIES OF SUBSIDIARY TRUST As discussed in Note 9 to the consolidated financial statements included elsewhere herein, Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% Trust Convertible Preferred Securities ("TCP Securities") in July 1996. The TCP Securities had a maturity date of June 15, 2026. However, in October 1999, Devon issued notice to the holders of the TCP Securities that it was exercising its right to redeem such securities on November 30, 1999. Substantially all of the holders of the TCP Securities elected to exercise their conversion rights instead of receiving the redemption cash value. As a result, all but 950 of the 2.99 million units of TCP Securities were exchanged for shares of Devon common stock. As a result, Devon issued approximately 4.9 million shares of common stock for substantially all of the outstanding units of TCP Securities. The redemption price for the 950 units redeemed was approximately $50,000.
1999 vs. 1998 The TCP Securities distributions in 1999 were $6.9 million compared to $9.7 million in 1998. Substantially all of the TCP Securities were exchanged for shares of Devon common stock on November 30, 1999. Therefore, there was no fourth quarter 1999 distribution on the exchanged TCP Securities.
1998 vs. 1997 Distributions on the TCP Securities were $9.7 million in both 1998 and 1997.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less deferred taxes, is written off as an expense.
35

1998 Reduction. As of September 30, 1998, the carrying value of Devon's domestic properties, less deferred income taxes, exceeded the full cost ceiling by $88 million. Accordingly, a $126.9 million pre-tax reduction of the carrying value of such properties was recorded in the third quarter of 1998. This reduction was partially offset by a related $38.9 million deferred income tax benefit, resulting in an after-tax charge of $88 million.
1997 Reduction. As of December 31, 1997, the carrying value of Northstar's oil and gas properties, less deferred income taxes, exceeded the full cost ceiling by $397.9 million. Accordingly, a $625.5 million pre-tax reduction of the carrying value of such properties was recorded in the fourth quarter of 1997. This reduction was partially offset by a related $227.6 million deferred income tax benefit, resulting in an after-tax charge of $397.9 million.
INCOME TAXES 1999 vs. 1998 Devon's 1999 financial tax rate was 41% of earnings before income tax expense. This rate was higher than the statutory federal tax rate of 35% due to the effect of goodwill amortization that is not deductible for income tax purposes and the effect of Canadian pre-tax earnings being taxed at higher rates than the U.S. rate. The 1998 financial tax benefit rate was 20%. This rate was materially affected by a portion of the $126.9 million reduction of carrying value of oil and gas properties recorded in 1998 that was not deductible for income tax purposes.
1998 vs. 1997 Devon's effective financial income tax benefit rate in 1998 was 20% compared to a benefit rate in 1997 of 37%. The benefit rate in 1998 was lower than in 1997 due to a combination of a smaller pre-tax loss in 1998 and certain 1998 financial expenses that are not deductible for income tax purposes. Approximately $27.2 million of the $126.9 million reduction of carrying value of oil and gas properties related to costs, which are not deductible for income taxes. Also, approximately $5.6 million of the Northstar Combination expenses and $4.0 million of the deferred effect of changes in foreign currency exchange rate on subsidiary's long-term debt are not deductible for income tax purposes.
CAPITAL EXPENDITURES, CAPITAL RESOURCES AND LIQUIDITY
The following discussion of capital expenditures, capital resources and liquidity should be read in conjunction with the consolidated statements of cash flows included in "Item 8. Financial Statements and Supplementary Data."
CAPITAL EXPENDITURES Approximately $314.8 million was spent in 1999 for capital expenditures, of which $240.7 million was related to the acquisition, drilling or development of oil and gas properties and $69.3 million was spent on the gas gathering and processing project in Wyoming. These amounts compare to 1998 total expenditures of $375.5 million ($371.3 million of which was related to oil and gas properties) and 1997 total expenditures of $288.0 million ($279.9 million of which was related to oil and gas properties.)
OTHER CASH USES Devon's common stock dividends were $12.7 million, $7.3 million and $6.4 million in 1999, 1998 and 1997, respectively. Devon also paid $3.7 million of preferred stock dividends in the last 4 1/2 months of 1999 following the PennzEnergy merger.
36

CAPITAL RESOURCES AND LIQUIDITY Net cash provided by operating activities ("operating cash flow") has historically been the primary source of Devon's capital and short-term liquidity. Operating cash flow was $205.6 million, $191.6 million and $253.1 million in 1999, 1998 and 1997, respectively. The trends in operating cash flow during these periods have generally followed those of the various revenue and expense items previously discussed.
In addition to operating cash flow, Devon's credit lines and the private placement of long-term debt have been an important source of capital and liquidity. In 1999, debt repayments exceeded borrowings by $223.9 million. During the years 1998 and 1997, long-term debt borrowings exceeded repayments by $55.3 million and $127.2 million, respectively.
On October 15, 1999, Devon entered into new unsecured long-term credit facilities aggregating $750 million (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $475 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced Devon's previous facilities that totaled $400 million.
Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate that is also available at Devon's option. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly.
The $475 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $275 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until October 13, 2000 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt borrowed under the Tranche B facility matures two years following the end of the Tranche B Revolving Period. At the end of 1999, Devon had $200 million borrowed under the Tranche A facility and none borrowed under the Tranche B facility.
Devon may borrow funds under the $275 million Canadian Facility until October 13, 2000 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 45 and 90 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semi-annual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. At December 31, 1999, there was $114.3 million borrowed under the Canadian Facility.
Another significant source of liquidity in 1999 was the $402 million received from the sale of approximately 10.3 million shares of Devon's common stock in a public offering. The proceeds were primarily used to retire $350 million of long-term debt in the fourth quarter of 1999. The retired debt, which Devon assumed in the PennzEnergy merger, had an average interest rate of 10% per year.
37

YEAR 2000 STATUS
Devon's company-wide Year 2000 Project ("the Project") was completed on schedule. The Project addressed the "Year 2000" issue caused by computer programs being written utilizing two digits rather than four to define an applicable year. Total costs related to the Project were approximately $1.3 million, of which $1.0 million related to capital items and $0.3 million to expense items.
During the rollover from December 31, 1999 to January 1, 2000, Devon followed a Year 2000 rollover plan for reporting, documenting and remediating Year 2000 errors. These plans included such tasks as on-site testing and verification of systems at January 1, 2000. Currently, there have been no business-critical failures reported due to Year 2000 errors. However, there were two failures reported for non-critical systems, both of which were remedied by vendor-supplied corrections by January 4, 2000.
Devon will continue to monitor systems for errors due to Year 2000 failures through the processing of leap year related data. Devon does not expect to incur significant operational problems due to the Year 2000 issue. However, if all Year 2000 issues are not properly and timely identified, assessed, remediated and tested, there can be no assurances that the Year 2000 issue will not materially impact Devon's results of operations or adversely affect its relationships with customers, vendors, or others. Additionally, there can be no assurance that the Year 2000 issues of other entities will not have a material impact on Devon's systems or results of operations.
2000 ESTIMATES
The forward-looking statements provided in this discussion are based on management's examination of historical operating trends, the December 31, 1999 reserve reports of independent petroleum engineers and other data in Devon's possession or available from third parties. Devon cautions that its future oil, gas and NGLs production, revenues and expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development and production and sale of oil and gas. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below. Also, the financial results of Devon's foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in the context of line items most affected by such risks.
SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION ESTIMATES Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and world-wide economic growth, weather and other substantially variable factors. These factors are beyond Devon's control and are difficult to predict. In addition to volatility in general, Devon's oil, gas and NGLs prices may vary considerably due to differences between regional markets, transportation availability and demand for different grades of oil, gas and NGLs. Over 97% of Devon's revenues are attributable to sales of these three commodities. Consequently, Devon's financial results and resources are highly influenced by this price volatility.
38

Estimates for Devon's future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil and gas will continue at levels that allow for profitable production of these products. There can be no assurance of such stability.
Certain of Devon's individual oil and gas properties, such as the Northeast Blanco Unit in the San Juan Basin, are of a size such that significant declines in production at these properties could have a material impact on the overall financial results.
The production, transportation and marketing of oil, natural gas and NGLs are complex processes which are subject to disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were prepared assuming demand, curtailment, producibility and general market conditions for Devon's oil, natural gas and NGLs for 2000 will be substantially similar to those of 1999, unless otherwise noted. Given the general limitations expressed herein, Devon's forward-looking statements for 2000 are set forth below. Unless otherwise noted, all of the following dollar amounts are expressed in U.S. dollars. Those amounts related to Canadian operations have been converted to U.S. dollars using the year-end 1999 exchange rate of $0.6929 U.S. dollar to $1.00 Canadian dollar. The actual 2000 exchange rate may vary materially from the year-end 1999 rate used. Such variations could have a material effect on the following Canadian estimates.
GEOGRAPHIC REPORTING AREAS FOR 2000 The following estimates of production, average price differentials and capital expenditures are provided separately for each of Devon's geographic divisions established after the PennzEnergy merger. These divisions are as follows:
o the Southern Division, which operates oil and gas properties located primarily in the onshore South Texas and Gulf Coast areas and offshore in the Gulf of Mexico;
o the Northern Division, which operates all properties located in the United States other than those operated by the Southern Division;
o Canada; and
o International Division, which encompasses all oil and gas properties that lie outside of the United States and Canada.
YEAR 2000 POTENTIAL OPERATING ITEMS
OIL PRODUCTION Devon expects its oil production in 2000 to total between 21.1 million barrels and 23.9 million barrels. Northern Division production is expected to be between 9.8 million barrels and 11.1 million barrels, Southern Division production is expected to be between 5.7 million barrels and 6.5 million barrels, Canadian production is expected to be between 4.3 million barrels and 4.9 million barrels, and International production is expected to be between 1.3 million barrels and 1.4 million barrels.
39

OIL PRICES Devon expects its 2000 net oil prices per barrel will average from $1.50 to $2.40 above West Texas Intermediate ("WTI") posted prices for its Northern Division production and $0.10 to $0.95 above WTI posted prices for its Southern Division production.
Devon expects to receive a price from $1.25 to $2.25 below WTI posted prices for its Canadian production. This expected range includes an estimated $0.30 per barrel decrease resulting from foreign currency hedges. These hedges, in which Devon will sell $30 million in 2000 at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same amount of dollars at the floating exchange rate, offset a portion of the exposure to currency fluctuations on those Canadian oil sales that are based on U.S. dollar prices. The $0.30 per barrel decrease is based on the assumption that the year-end 1999 Canadian-to-U.S. conversion rate of $0.6929 remains constant during 2000.
Almost 90% of expected International oil production in 2000 is in Venezuela. Due to the terms of the controlling production sharing contract, the net price Devon records for its Venezuelan oil production is substantially less than WTI posted prices.
GAS PRODUCTION Devon expects its 2000 gas production to total between 269 Bcf and 306 Bcf. It is expected that Northern Division production will be between 115 Bcf and 130 Bcf, and Southern Division production will be between 93 Bcf and 106 Bcf. Canadian production is expected to be between 61 Bcf and 70 Bcf. No significant gas production is expected in 2000 from Devon's International properties.
GAS PRICES - FIXED Through various fixed price contracts or hedging instruments, Devon has fixed the price it will receive in 2000 on a portion of its natural gas production. The Northern Division has fixed volumes of 9.5 Bcf at $1.97 per Mcf, which is a modest amount of total expected Northern Division production. Devon's Canadian operation has fixed volumes of 25.6 Bcf at $1.44 per Mcf, which is a more significant amount of total expected Canadian production.
GAS PRICES - FLOATING For the gas production for which prices have not been fixed, Devon's Northern Division production is expected to average from $0.25 less than Texas Gulf Coast spot averages ("TGC") to $0.05 more than TGC, Southern Division production is expected to average from an amount equal to TGC to $0.30 more than TGC and Canadian production is expected to average from $0.40 to $0.80 less than the New York Mercantile Exchange price.
NGLS PRODUCTION Devon expects its 2000 production of NGLs to total between 6.6 million barrels and 7.6 million barrels. Between 4.7 million barrels and 5.4 million barrels are expected to be produced in the Northern Division, between 1.5 million barrels and 1.7 million barrels are expected to be produced in the Southern Division, and between 0.4 million barrels and 0.5 million barrels are expected to be produced in Canada. No significant NGLs production is expected in 2000 from Devon's International properties.
OTHER REVENUES Devon's other revenues in 2000 are expected to be between $29 million and $33 million. Approximately $18.5 million of 2000's expected other revenues is from dividends on Devon's investment of 7.1 million shares of Chevron Corporation common stock.
PRODUCTION AND OPERATING EXPENSES Devon's production and operating expenses vary in response to several factors. Among the most significant of these factors are additions to or deletions from Devon's property base, changes in production taxes, general changes in the prices
40

of services and materials that are used in the operation of the properties and the amount of repair and workover activity required.
Oil, gas and NGLs prices will have a direct effect on production taxes to be incurred in 2000. Future prices also could have an effect on whether proposed workover projects are economically feasible. These factors, coupled with the uncertainty of future oil, gas and NGLs prices, increase the uncertainty inherent in estimating future production and operating costs. Given these uncertainties, Devon estimates that year 2000 total production and operating costs will be between $288 million and $318 million.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") The 2000 oil and gas property DD&A rate will depend on various factors. Most notable among such factors are the amount of proved reserves that could be added from drilling or acquisition efforts in 2000 compared to the costs incurred for such efforts, and the revisions to Devon's year-end 1999 reserve estimates that, based on prior experience, are likely to be made during 2000.
Devon's consolidated oil and gas property DD&A rate as of January 1, 2000, was $5.41 per Boe. Assuming a full year 2000 oil and gas property DD&A rate of between $5.25 per Boe and $6.00 per Boe, Devon expects that its consolidated oil and gas property DD&A expense in 2000 will be between $400 million and $460 million.
In addition to its oil and gas property DD&A expense, Devon also expects to record goodwill amortization in 2000 of between $37 million and $41 million. The goodwill was recorded in connection with the PennzEnergy merger. Additionally, Devon expects its 2000 DD&A expense related to non-oil and gas property fixed assets to total between $27 million and $29 million.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon's G&A includes the costs of many different goods and services used in support of its business. These goods and services are subject to general price level increases or decreases. In addition, Devon's G&A varies with its level of activity and the related staffing needs as well as with the amount of professional services required during any given period. Should Devon's needs or the prices of the required goods and services differ significantly from current expectations, actual G&A could vary materially from the estimate. Given these limitations, consolidated G&A in 2000 is expected to be between $48 million and $53 million.
INTEREST EXPENSE Future interest rates and oil, natural gas and NGLs prices have a significant effect on Devon's interest expense. Approximately $1.2 billion of Devon's January 21, 2000, long-term debt balance of $1.7 billion bears interest at fixed rates. Such fixed rates remove the uncertainty of future interest rates from some, but not all, of Devon's long-term debt. Also, Devon can only marginally influence the prices, and the resulting cash flow, it will receive in 2000 from sales of oil, gas and NGLs. These factors increase the margin of error inherent in estimating future interest expense. Other factors, which affect interest expense, such as the amount and timing of capital expenditures, are within Devon's control. Given the uncertainty of future interest rates and commodity prices, Devon estimates that the consolidated interest expense in 2000 will be between $103 million and $114 million.
41

DEFERRED EFFECT OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATE ON SUBSIDIARY'S LONG-TERM DEBT Devon's Canadian subsidiary Northstar had $225 million of U.S. dollar denominated debt that gave rise to this item in prior periods. This debt was retired in January 2000. The Canadian-to-U.S. dollar exchange rate dropped slightly in January prior to the debt retirement. As a result, $2.4 million of expense was recognized in January 2000.
REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES As of December 31, 1999, the full cost ceiling exceeded Devon's carrying value of oil and gas properties, less deferred income taxes. However, such excess could easily be eliminated by declines in oil and/or gas prices between year-end 1999 and the end of any quarter during 2000. The result would be a 2000 reduction of the carrying value of oil and gas properties.
INCOME TAXES Devon expects its consolidated financial income tax rate in 2000 to be between 48% and 57%. These rates are the combined current and deferred tax rates. There are certain items that will have a fixed impact on 2000's income tax expense regardless of the level of pre-tax earnings that are produced. These items include Section 29 tax credits in the U.S., which reduce income taxes based on production levels of certain properties and are not necessarily affected by pre-tax financial earnings. The amount of Section 29 tax credits expected to be used to offset financial income tax expense in 2000 is approximately $4 million. Also, Devon's Canadian subsidiaries are subject to Canada's "large corporation tax" of approximately $2 million, which is based on total capitalization levels, not pre-tax earnings. The financial income tax in 2000 will also be increased by approximately $16 million due to the financial amortization of certain costs, such as goodwill amortization, that are not deductible for income tax purposes. Significant changes in estimated production levels of oil, gas and NGLs, the prices of such products, or any of the various expense items could materially alter the effect of the aforementioned items on 2000's financial income tax rates.
Based on its current expectations of 2000 taxable income, Devon anticipates its current portion of 2000 income taxes will be $36 million to $40 million. However, unanticipated revenue and/or expense fluctuations could easily make these tax estimates inaccurate.
PROPERTY ACQUISITIONS AND DIVESTITURES Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget," nor can it reasonably predict, the timing or size of such possible acquisitions, if any.
During 2000, Devon contemplates the disposition of certain oil and gas properties (the "Disposition Properties"). The Disposition Properties are predominantly properties that are either outside of Devon's core-operating areas or otherwise do not fit Devon's current strategic objectives. Most, but not all, of such properties were acquired in the August 1999 merger with PennzEnergy. The Disposition Properties are located in the U.S., Canada and other International areas. At this time, Devon is in the early stages of the disposition process, and it is impossible to identify when, or if, the dispositions will occur.
The estimates of Devon's 2000 results set forth earlier in this section include the full-year results from the Disposition Properties without any effect given to their potential disposition. The actual effect the dispositions will have on Devon's overall estimates will depend upon the actual timing of the dispositions. The estimated full-year results from the Disposition Properties that are included in the overall 2000 estimates include oil production of between 4.1 million barrels and 4.6
42

million barrels, gas production of between 2.1 Bcf and 2.3 Bcf and NGLs production of between 0.9 million barrels and 1.0 million barrels and production and operating expenses of between $37.8 million and $41.8 million.
Because Devon is in the early stages of the disposition process, it is difficult to accurately predict the amount of proceeds to be generated from the property dispositions. However, the dispositions are expected to increase Devon's oil and gas property depreciation, depletion and amortization rate by $0.35 per Boe to $0.45 per Boe after all dispositions are completed.
YEAR 2000 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY
CAPITAL EXPENDITURES Devon's capital expenditures budget is based on an expected range of future oil, natural gas and NGLs prices as well as the expected costs of the capital additions. Should Devon's price expectations for its future production change significantly, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2000 capital expenditures. In addition, if the actual costs of the budgeted items vary significantly from the anticipated amounts, actual capital expenditures could vary materially from Devon's estimates.
Though Devon has completed several major property acquisitions in recent years, these transactions are opportunity driven. Thus, Devon does not "budget", nor can it reasonably predict, the timing or size of such possible acquisitions, if any.
Devon expects its capital expenditures for the year 2000 will be materially higher than those for 1999. For 1999, Devon's capital expenditures for exploration, drilling and development efforts were $217 million. However, for the year 2000, Devon expects capital expenditures for exploration, drilling and development efforts to total between $480 million and $510 million. These amounts include between $110 million and $130 million for drilling and facilities costs related to reserves classified as proved as of year-end 1999. In addition, these amounts include between $240 million and $260 million for other lower risk/reward projects and between $120 million and $130 million for new, higher risk/reward projects. The following table shows expected drilling and facilities expenditures by major operating division.
EXPLORATION, DRILLING AND PRODUCTION FACILITIES EXPENDITURES ($ IN MILLIONS)

                                NORTHERN     SOUTHERN                 INTERNATIONAL
                                DIVISION     DIVISION      CANADA        DIVISION
                                ---------   ----------    ---------   -------------
Related to Proved Reserves      $60 -$ 70    $30 -$ 35    $5  -$ 10      $8 -$12
Lower Risk/Reward Projects      $100-$110    $65 -$ 75    $70 -$ 80           --
Higher Risk/Reward Projects     $15 -$ 20    $45 -$ 50    $30 -$ 35      $22-$28
      Total                     $175-$200    $140-$160    $105-$125      $30-$40	

In addition to these expenditures for exploration, drilling and development, Devon is participating through a joint venture in the construction of gas gathering and processing systems in the Powder River Basin of Wyoming. Devon expects to spend from $10 million to $20 million as its share of the project in 2000. Devon also expects to capitalize between $25 million and $35 million of G&A expenses in accordance with the full cost method of accounting. Also, Devon expects to spend from $10 million to $20 million for plugging and abandonment costs on some of its oil and gas properties.
43

OTHER CASH USES Devon's management expects the policy of paying a quarterly dividend to continue. With the current $0.05 per share quarterly dividend rate and 86.1 million shares of common stock outstanding, 2000 dividends on common stock are expected to approximate $17 million. Dividends paid on preferred stock should total $9.7 million in 2000.
CAPITAL RESOURCES AND LIQUIDITY Devon's estimated 2000 cash uses, including its exploration, drilling and development activities, are expected to be funded primarily through a combination of working capital and operating cash flow, with the remainder, if any, funded with borrowings from Devon's credit facilities. The amount of operating cash flow to be generated during 2000 is uncertain due to the factors affecting revenues and expenses as previously cited. However, Devon expects its combined capital resources to be more than adequate to fund its anticipated capital expenditures and other cash uses for 2000. As of January 21, 2000, Devon had $337 million available under its $750 million credit facilities. If significant acquisitions or other unplanned capital requirements arise during the year, Devon could utilize its existing credit facilities and/or seek to establish and utilize other sources of financing.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires the recognition of all derivatives as either assets or liabilities in the statement of financial position and measurement of those instruments at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge. The accounting for changes in the fair value of a derivative (that is gains and losses) depends on the intended use of the derivative and whether it qualifies as a hedge. A subsequent pronouncement, SFAS 137, was issued in July, 1999 that delayed the effective date of SFAS 133 until fiscal years beginning after June 15, 2000. Devon plans to adopt the provision of SFAS 133 in the first quarter of the year ending December 31, 2001, and is currently evaluating the effects of this pronouncement.
44

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Devon's potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how Devon views and manages its ongoing market risk exposures. All of Devon's market risk sensitive instruments were entered into for purposes other than trading.
COMMODITY PRICE RISK Devon's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to its U.S. and Canadian natural gas production. Pricing for oil and gas production has been volatile and unpredictable for several years.
Devon periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through financial price swaps whereby Devon will receive a fixed price for its production and pay a variable market price to the contract counterparty. These financial hedging activities are intended to support oil and natural gas prices at targeted levels and to manage Devon's exposure to oil and gas price fluctuations. Realized gains or losses from the settlement of these financial hedging instruments are recognized in oil and gas sales when the associated production occurs. The gains and losses realized as a result of these hedging activities are substantially offset in the cash market when the hedged commodity is delivered. Devon does not hold or issue derivative instruments for trading purposes.
As of year-end 1999, Devon had financial gas price hedging instruments in place which represented approximately 18 Bcf, 13 Bcf and 3 Bcf of gas production in the years 2000, 2001 and 2002, respectively. The 2000 hedged gas volumes represent approximately 6% of expected 2000 total production. See "Item
7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2000 Estimates."
Devon uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of its commodity hedging instruments. At December 31, 1999, a 10% increase in the underlying commodities' prices would have reduced the fair value of Devon's commodity hedging instruments by $7.7 million.
In addition to the commodity hedging instruments described above, Devon also manages its exposure to gas price risks by periodically entering into fixed-price gas contracts. All of Devon's existing fixed-price contracts relate to its Canadian gas production. For each of the years of 2000 through 2004, Devon's fixed-price gas contracts cover approximately 17 Bcf, 12 Bcf, 10 Bcf, 6 Bcf and 6 Bcf of production, respectively. Devon also has Canadian gas volumes subject to fixed-price contracts in the years from 2005 through 2016, but the yearly volumes are less than 6 Bcf. The amount of 2000's production covered by fixed-price contracts represents approximately 6% of expected 2000 total production. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2000 Estimates."
45

INTEREST RATE RISK At December 31, 1999, Devon had long-term debt outstanding of $1.79 billion. Of this amount, $1.47 billion, or 82%, bears interest at fixed rates averaging 6.9%. The remaining $0.32 billion of debt outstanding at the end of 1999 bears interest at floating rates which averaged 6.2% at the end of 1999.
In mid-January 2000, Devon utilized $75 million of cash on hand and $150 million of borrowings from its long-term credit facilities, which bear interest at floating rates, to retire $225 million of fixed-rate long-term debt. This fixed-rate debt retired had an average interest rate of 6.8% per year. Also in mid-January 2000, Devon used approximately $50 million of cash on hand to reduce year-end 1999 borrowings under its credit facilities. These early 2000 transactions left Devon with $1.66 billion of total long-term debt, of which $1.25 billion, or 75%, bears interest at fixed rates averaging 6.9%. The remaining $0.41 billion of floating-rate debt borrowed under the credit facilities bears interest, as of January 21, 2000, at an average rate of 6.0%.
The terms of the credit facilities in place allow interest rates to be fixed at Devon's option for periods of between 30 to 180 days. A 10% increase in short-term interest rates on the floating-rate debt outstanding as of January 21, 2000, would equal approximately 60 basis points. Such an increase in interest rates would increase Devon's 2000 interest expense by approximately $2.5 million assuming borrowed amounts remain outstanding.
The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments.
FOREIGN CURRENCY RISK Devon's net assets, net earnings and cash flows from its foreign subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the applicable functional currency. Assets and liabilities of the foreign subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using the average exchange rate during the reporting period.
Substantially all of Devon's Canadian oil sales are paid in Canadian dollars, but at amounts based on the U.S. dollar price of oil. Therefore, currency fluctuations between the Canadian and U.S. dollars impact the amount of Canadian dollars received by Devon's Canadian subsidiaries for their oil production. To mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues, Devon has existing foreign currency exchange rate swaps. Under such swap agreements, in 2000 Devon will sell $30 million at an average Canadian-to-U.S. exchange rate of $0.7265 and buy the same amount of dollars at the floating exchange rate. The amount of gains or losses realized from such swaps are included as increases or decreases to realized oil sales. At the year-end 1999 exchange rate, these swaps would result in decreases to 2000's annual oil sales of approximately $1.4 million. A further $0.03 decrease in the Canadian-to-U.S. dollar exchange rate in 2000 would result in an additional decrease in oil sales of approximately $1.3 million.
For purposes of the sensitivity analysis described above for changes in the Canadian dollar exchange rate, a change in the rate of $0.03 was used as opposed to a 10% change in the rate. During the last seven years, the Canadian-to-U.S. dollar exchange rate has fluctuated an average of approximately 4% per year, and no year's fluctuation was greater than 7%. The $0.03 change used in the above analysis represents an approximate 4% change in the year-end 1999 rate.
46

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES

                                                                            Page
                                                                            ----
Independent Auditors' Reports..............................................  48

Consolidated Financial Statements:
   Consolidated Balance Sheets
    December 31, 1999, 1998 and 1997.......................................  50

   Consolidated Statements of Operations
    Years Ended December 31, 1999, 1998 and 1997...........................  51

   Consolidated Statements of Stockholders' Equity
    Years Ended December 31, 1999, 1998 and 1997...........................  52

   Consolidated Statements of Cash Flows
    Years Ended December 31, 1999, 1998 and 1997...........................  53

   Notes to Consolidated Financial Statements
    December 31, 1999, 1998 and 1997.......................................  54	

All financial statement schedules are omitted as they are inapplicable or the required information has been included in the consolidated financial statements or notes thereto.
47

INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 1999, 1998 and 1997, and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the 1998 and 1997 financial statements of Northstar Energy Corporation, a wholly-owned subsidiary, which statements reflect total assets constituting 31% and 32% and total revenues constituting 38% and 37% in 1998 and 1997, respectively, of the related consolidated totals. The 1998 and 1997 financial statements of Northstar Energy Corporation were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Northstar Energy Corporation in 1998 and 1997, is based solely on the reports of the other auditors.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Devon Energy Corporation and subsidiaries as of December 31, 1999, 1998 and 1997, and the results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
KPMG LLP
Oklahoma City, Oklahoma
February 9, 2000
48

AUDITORS' REPORT TO THE SHAREHOLDERS
We have audited the consolidated balance sheets of Northstar Energy Corporation (a wholly owned subsidiary of Devon Energy Corporation) as at December 31, 1998 and 1997 and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity and cash flows for the years then ended (not separately included herein). These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards, which are substantially similar to generally accepted auditing standards in the United States. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 1998 and 1997, and the results of its operations and the changes in its cash flow for the years then ended in accordance with generally accepted accounting principles in the United States.

/s/ DELOITTE & TOUCHE LLP
-------------------------------------
Deloitte & Touche LLP
Chartered Accountants	

Calgary, Alberta
Canada
January 20, 1999
49

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
 (IN THOUSANDS, EXCEPT SHARE DATA)

                                                                                            DECEMBER 31,
                                                                           ---------------------------------------------
                                                                              1999             1998             1997
                                                                           -----------      -----------      -----------
ASSETS
Current assets:
    Cash and cash equivalents                                              $   167,167           19,154           42,065
    Accounts receivable                                                        209,405           83,858           96,828
    Inventories                                                                 13,441            2,750            4,012
    Assets held for sale                                                            --               --           43,548
    Deferred income taxes                                                        4,886              605              434
    Investments and other current assets                                        22,295            4,281           26,370
                                                                           -----------      -----------      -----------
        Total current assets                                                   417,194          110,648          213,257
                                                                           -----------      -----------      -----------
Property and equipment, at cost, based on the full
  cost method of accounting for oil and gas properties                       4,974,810        2,610,511        2,320,735
    Less accumulated depreciation, depletion and
        amortization                                                         1,818,890        1,509,583        1,325,452
                                                                           -----------      -----------      -----------
                                                                             3,155,920        1,100,928          995,283
Investment in Chevron Corporation common stock,
  at fair value                                                                614,382               --               --
Goodwill, net of amortization                                                  322,800               --               --
Other assets                                                                   112,864           14,780           40,446
                                                                           -----------      -----------      -----------
        Total assets                                                       $ 4,623,160        1,226,356        1,248,986
                                                                           ===========      ===========      ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
    Accounts payable:
        Trade                                                                   75,625           40,177           46,003
        Revenues and royalties due to others                                    58,130           12,508           13,898
    Income taxes payable                                                        11,287               --            5,029
    Current portion of long-term debt                                               --               --           48,979
    Accrued interest payable                                                    26,270            3,688            6,274
    Merger related expenses payable                                             32,504            7,882               --
    Accrued expenses                                                            23,628           16,401           16,131
                                                                           -----------      -----------      -----------
        Total current liabilities                                              227,444           80,656          136,314
                                                                           -----------      -----------      -----------
Other liabilities                                                              192,210           34,747           29,464
Debentures exchangeable into shares of Chevron
  Corporation common stock                                                     760,313               --               --
Other long-term debt                                                         1,026,808          405,271          305,337
Deferred income taxes                                                          390,865           33,219           31,825
Company-obligated mandatorily redeemable convertible
  preferred securities of subsidiary trust holding
  solely 6.5% convertible junior subordinated
  debentures of Devon Energy Corporation                                            --          149,500          149,500
Stockholders' equity:
    Preferred stock of $1.00 par value ($100 liquidation value)
        Authorized 4,500,000 shares; issued 1,500,000
        in 1999 and none in 1998 and 1997                                        1,500               --               --
    Common stock of $.10 par value
        Authorized 400,000,000 shares; issued 86,085,000
        in 1999, 48,425,000 in 1998, and 48,290,000 in 1997                      8,608            4,842            4,829
    Additional paid-in capital                                               2,246,652          796,992          794,176
    Retained earnings (accumulated deficit)                                   (164,698)        (242,909)        (175,346)
    Accumulated other comprehensive loss                                       (66,542)         (35,962)         (27,113)
                                                                           -----------      -----------      -----------
        Total stockholders' equity                                           2,025,520          522,963          596,546
                                                                           -----------      -----------      -----------
Commitments and contingencies (Notes 12 and 13)
        Total liabilities and stockholders' equity                         $ 4,623,160        1,226,356        1,248,986
                                                                           ===========      ===========      ===========	

See accompanying notes to consolidated financial statements
50

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

                                                                                YEAR ENDED DECEMBER 31,
                                                                      ------------------------------------------
                                                                         1999            1998            1997
                                                                      ----------      ----------      ----------
REVENUES
   Oil sales                                                          $  273,234         143,624         207,725
   Gas sales                                                             385,925         209,344         219,459
   Natural gas liquids sales                                              56,344          16,692          24,920
   Other                                                                  18,996          17,848          47,555
                                                                      ----------      ----------      ----------
      Total revenues                                                     734,499         387,508         499,659
                                                                      ----------      ----------      ----------

COSTS AND EXPENSES
   Lease operating expenses                                              166,848         113,484         100,897
   Production taxes                                                       23,055          13,916          19,227
   Depreciation, depletion and amortization of property
      and equipment                                                      254,275         123,844         169,108
   Amortization of goodwill                                               16,111              --              --
   General and administrative expenses                                    53,845          23,554          24,381
   Northstar Combination expenses                                             --          13,149              --
   Interest expense                                                       66,913          22,632          18,788
   Deferred effect of changes in foreign currency
     exchange rate on subsidiary's long-term debt                        (13,154)         16,104           5,860
   Distributions on preferred securities of
     subsidiary trust                                                      6,884           9,717           9,717
   Reduction of carrying value of oil and gas properties                      --         126,900         625,514
                                                                      ----------      ----------      ----------
      Total costs and expenses                                           574,777         463,300         973,492
                                                                      ----------      ----------      ----------

Earnings (loss) before income tax expense (benefit)                      159,722         (75,792)       (473,833)

INCOME TAX EXPENSE (BENEFIT)
   Current                                                                24,656           7,687          26,857
   Deferred                                                               40,510         (23,194)       (200,699)
                                                                      ----------      ----------      ----------
      Total income tax expense (benefit)                                  65,166         (15,507)       (173,842)
                                                                      ----------      ----------      ----------

Net earnings  (loss)                                                      94,556         (60,285)       (299,991)
Preferred stock dividends                                                  3,651              --              --
                                                                      ----------      ----------      ----------

Net earnings (loss) applicable to common shareholders                 $   90,905         (60,285)       (299,991)
                                                                      ==========      ==========      ==========

Net earnings (loss) per average common share outstanding:
      Basic                                                           $     1.51           (1.25)          (6.38)
                                                                      ==========      ==========      ==========
      Diluted                                                         $     1.46           (1.25)          (6.38)
                                                                      ==========      ==========      ==========

Weighted average common shares
      outstanding - basic                                                 60,015          48,376          47,040
                                                                      ==========      ==========      ==========	

See accompanying notes to consolidated financial statements.
51

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
 (IN THOUSANDS)

                                                                                                            ACCUMU-
                                                                                                RETAINED     LATED
                                                                                                EARNINGS     OTHER      TOTAL
                                                                                   ADDITIONAL   (ACCUMU-    COMPRE-     STOCK-
                                                        PREFERRED        COMMON     PAID-IN      LATED      HENSIVE    HOLDERS'
                                                          STOCK           STOCK      CAPITAL     DEFICIT)     LOSS      EQUITY
                                                        ----------        -----     ---------    --------    -------    ---------
Balance as of December 31, 1996                         $       --        4,288       556,049     131,090    (12,655)     678,772

Comprehensive loss:
  Net loss                                                      --           --            --    (299,991)        --     (299,991)
  Other comprehensive loss - foreign
    currency translation adjustments                            --           --            --          --    (14,458)     (14,458)
                                                                                                                       ----------
  Comprehensive loss                                            --           --            --          --         --     (314,449)

Stock issued                                                    --        1,027       453,441          --         --      454,468
Stock repurchased                                               --         (486)     (216,514)         --         --     (217,000)
Tax benefit related to employee stock options                   --           --         1,200          --         --        1,200
Dividends on common stock                                       --           --            --      (6,445)        --       (6,445)
                                                        ----------     --------    ----------  ----------  ---------   ----------

Balance as of December 31, 1997                                 --        4,829       794,176    (175,346)   (27,113)     596,546

Comprehensive loss:
  Net loss                                                      --           --            --     (60,285)        --      (60,285)
  Other comprehensive loss, net of tax:
     Foreign currency translation adjustments                   --           --            --          --     (8,130)      (8,130)
     Minimum pension liability adjustment                       --           --            --          --       (719)        (719)
                                                                                                                       ----------
     Other comprehensive loss                                   --           --            --          --         --       (8,849)
                                                                                                                       ----------
  Comprehensive loss                                            --           --            --          --         --      (69,134)

Stock issued                                                    --           13         2,816          --         --        2,829
Dividends on common stock                                       --           --            --      (7,278)        --       (7,278)
                                                        ----------        -----     ---------    --------    -------    ---------

Balance as of December 31, 1998                                 --        4,842       796,992    (242,909)   (35,962)     522,963

Comprehensive earnings:
  Net earnings                                                  --           --            --      94,556         --       94,556
  Other comprehensive loss, net of tax:
     Foreign currency translation adjustments                   --           --            --          --      7,517        7,517
     Minimum pension liability adjustment                       --           --            --          --       (241)        (241)
     Unrealized losses on marketable securities                 --           --            --          --    (37,856)     (37,856)
                                                                                                                       ----------
     Other comprehensive loss                                   --           --            --          --         --      (30,580)
                                                                                                                       ----------
  Comprehensive earnings                                        --           --            --          --         --       63,976

Stock issued                                                 1,500        3,766     1,448,706          --         --    1,453,972
Tax benefit related to employee stock options                   --           --           954          --         --          954
Dividends on common stock                                       --           --            --     (12,694)        --      (12,694)
Dividends on preferred stock                                    --           --            --      (3,651)        --       (3,651)
                                                        ----------        -----     ---------    --------    -------    ---------

Balance as of December 31, 1999                         $    1,500        8,608     2,246,652    (164,698)   (66,542)   2,025,520
                                                        ==========     ========    ==========  ==========  =========   ==========	

See accompanying notes to consolidated financial statements.
52

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
 (IN THOUSANDS)

                                                                                            YEAR ENDED DECEMBER 31,
                                                                                ---------------------------------------------
                                                                                  1999                 1998             1997
                                                                                -----------           ------           ------
CASH FLOWS FROM OPERATING ACTIVITIES
     Net earnings (loss)                                                        $    94,556          (60,285)        (299,991)
     Adjustments to reconcile net earnings (loss) to net
        cash provided by operating activities:
           Depreciation, depletion and amortization of property
              and equipment                                                         254,275          123,844          169,108
           Amortization of goodwill                                                  16,111               --               --
           Amortization of premiums on debentures                                    (1,328)              --               --
           Deferred effect of changes in foreign currency
              exchange rate on subsidiary's long-term debt                          (13,154)          16,104            5,860
           Reduction of carrying value of oil and gas properties                         --          126,900          625,514
           Gain on sale of assets                                                      (122)            (164)         (29,573)
           Deferred income taxes (benefit)                                           40,510          (23,194)        (200,699)
           Other                                                                         --              901            2,964
           Changes in assets and liabilities, net of effects
              of acquisitions of businesses:
                 (Increase) decrease in:
                     Accounts receivable                                            (54,416)          10,160          (17,404)
                     Inventories                                                     (3,014)           1,173              198
                     Prepaid expenses                                                (1,518)             449             (930)
                     Other assets                                                   (22,073)             130             (874)
                 (Decrease) increase in:
                     Accounts payable                                               (39,195)          (3,439)             300
                     Income taxes payable                                           (19,418)          (5,126)             269
                     Accrued expenses                                               (30,187)           7,000              132
                     Long-term other liabilities                                    (15,399)          (2,882)          (1,818)
                                                                                -----------      -----------      -----------
                 Net cash provided by operating activities                          205,628          191,571          253,056
                                                                                -----------      -----------      -----------

CASH FLOWS FROM INVESTING ACTIVITIES
     Proceeds from sale of property and equipment                                    77,584           62,997          180,296
     Proceeds from sale of investments                                                   --           42,584               --
     Capital expenditures                                                          (314,805)        (375,512)        (287,991)
     Payments made for acquisition of business, net of cash acquired                (17,215)              --               --
     Increase in equity investment                                                       --               --          (32,428)
     Decrease (increase) in other assets                                                719           (2,029)          (7,460)
                                                                                -----------      -----------      -----------
                 Net cash used in investing activities                             (253,717)        (271,960)        (147,583)
                                                                                -----------      -----------      -----------

CASH FLOWS FROM FINANCING ACTIVITIES
     Proceeds from borrowings on long-term debt                                   1,705,917        1,292,020          817,785
     Principal payments on long-term debt                                        (1,929,809)      (1,236,713)        (690,627)
     Issuance of common stock, net of issuance costs                                422,232            2,829           12,878
     Retirement of preferred securities of subsidiary trust                             (50)              --               --
     Repurchase of common stock                                                          --               --         (217,000)
     Dividends paid on common stock                                                 (12,694)          (7,278)          (6,445)
     Dividends paid on preferred stock                                               (3,651)              --               --
     Increase in long-term other liabilities                                         13,453            6,760            6,268
                                                                                -----------      -----------      -----------
                 Net cash provided by (used in) financing activities                195,398           57,618          (77,141)
                                                                                -----------      -----------      -----------
Effect of exchange rate changes on cash                                                 704             (140)             316
                                                                                -----------      -----------      -----------
Net increase (decrease) in cash and cash equivalents                                148,013          (22,911)          28,648
Cash and cash equivalents at beginning of year                                       19,154           42,065           13,417
                                                                                -----------      -----------      -----------
Cash and cash equivalents at end of year                                        $   167,167           19,154           42,065
                                                                                ===========      ===========      ===========	

See accompanying notes to consolidated financial statements.
53

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by Devon Energy Corporation and subsidiaries ("Devon") reflect industry practices and conform to generally accepted accounting principles. The more significant of such policies are briefly discussed below.
Basis of Presentation and Principles of Consolidation
Devon is engaged primarily in oil and gas exploration, development and production, and the acquisition of producing properties. Such activities domestically are located primarily in five operating areas: Permian Basin, Mid-Continent, the Rocky Mountains, Gulf Coast onshore and offshore Gulf of Mexico. Devon's Canadian activities are located primarily in the Western Canadian Sedimentary Basin and Devon's international activities -- outside of North America -- are located primarily in Azerbaijan and Venezuela. Devon's share of the assets, liabilities, revenues and expenses of affiliated partnerships and the accounts of its wholly-owned subsidiaries are included in the accompanying consolidated financial statements. All significant intercompany accounts and transactions have been eliminated in consolidation.
Information concerning common stock and per share data assumes the exchange of all Exchangeable Shares issued in connection with the Northstar Combination described in Note 2.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from those estimates.
Inventories
Inventories, which consist primarily of injected gas and tubular goods, parts and supplies, are stated at cost, determined principally by the average cost method, which is not in excess of net realizable value.
Property and Equipment
Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and leasehold equipment, are capitalized. Net capitalized costs are limited to the estimated future net revenues, discounted at 10% per annum, from proved oil, natural gas and natural gas liquids reserves. Such limitations are imposed separately on a country-by-country basis. Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of one barrel of oil to six
54

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
thousand cubic feet of natural gas. No gain or loss is recognized upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and proved reserves.
Depreciation and amortization of other property and equipment, including leasehold improvements, are provided using the straight-line method based on estimated useful lives from 3 to 39 years.
Marketable Securities and Other Investments
Devon accounts for certain investments in debt and equity securities by following the requirements of Statement of Financial Accounting Standards ("SFAS") No. 115, "Accounting for Certain Investments in Debt and Equity Securities." This standard requires that, except for debt securities classified as "held-to-maturity," investments in debt and equity securities must be reported at fair value. As a result, Devon's investment in Chevron Corporation common stock, which is classified as "available for sale," is reported at fair value, with the tax effected unrealized gain or loss recognized in other comprehensive earnings and reported as a separate component of stockholders' equity. Devon's investments in other short-term securities are also classified as "available for sale."
Goodwill
Goodwill, which represents the excess of purchase price over the fair value of net assets acquired, is amortized by an equivalent unit-of-production method. Devon assesses the recoverability of this intangible asset by determining whether the amortization of the goodwill balance over its remaining life can be recovered through undiscounted future operating cash flows of the acquired properties. The amount of goodwill impairment, if any, is measured based on projected discounted future operating cash flows using a discount rate reflecting Devon's average cost of funds. The assessment of the recoverability of goodwill will be impacted if estimated future operating cash flows are not achieved.
Accumulated amortization of goodwill was $16.1 million at December 31, 1999.
Revenue Recognition and Gas Balancing
Oil and gas revenues are recognized when produced. During the course of normal operations, Devon and other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes produced. These volumetric imbalances are monitored over the lives of the wells' production capability. If an imbalance exists at the time the wells' reserves are depleted, cash settlements are made among the joint interest owners under a variety of arrangements.
Devon follows the sales method of accounting for gas imbalances. A liability is recorded when Devon's excess takes of natural gas volumes exceed its estimated remaining recoverable reserves. No
55

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
receivables are recorded for those wells where Devon has taken less than its ownership share of gas production.
Hedging Activities
Devon has periodically entered into oil and gas price swaps and foreign exchange rate swaps to manage its exposure to oil and gas price volatility. The foreign exchange rate swaps mitigate the effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian oil revenues that are predominantly based on U.S. dollar prices. The hedging instruments are usually placed with counterparties that Devon believes are minimal credit risks. The oil and gas reference prices upon which the price hedging instruments are based reflect various market indices that have a high degree of historical correlation with actual prices received by Devon.
Devon accounts for its hedging instruments using the deferral method of accounting. Under this method, realized gains and losses from Devon's price risk management activities are recognized in oil and gas revenues when the associated production occurs and the resulting cash flows are reported as cash flows from operating activities. Gains and losses on hedging contracts that are closed before the hedged production occurs are deferred until the production month originally hedged. In the event of a loss of correlation between changes in oil and gas reference prices under a hedging instrument and actual oil and gas prices, a gain or loss is recognized currently to the extent the hedging instrument has not offset changes in actual oil and gas prices.
Stock Options
Devon applies the intrinsic value-based method of accounting prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations, in accounting for its fixed plan stock options. As such, compensation expense would be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. SFAS No. 123, "Accounting for Stock-Based Compensation," established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As allowed by SFAS No. 123, Devon has elected to continue to apply the intrinsic value-based method of accounting described above, and has adopted the disclosure requirements of SFAS No. 123 which are included in Note 10.
Major Purchasers
In 1999, Columbia Energy Services Corporation accounted for 12% of Devon's combined oil, gas and natural gas liquids sales. Also, Aquila Energy Marketing Corporation accounted for 19% and 15% of Devon's combined oil, gas and natural gas liquids sales in 1998 and 1997, respectively.
56

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Income Taxes
Devon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. U.S. deferred income taxes have not been provided on Canadian earnings which are being permanently reinvested.
General and Administrative Expenses
General and administrative expenses are reported net of amounts allocated to working interest owners of the oil and gas properties operated by Devon and net of amounts capitalized pursuant to the full cost method of accounting.
Net Earnings Per Common Share
Basic earnings per share is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if Devon's dilutive outstanding stock options were exercised (calculated using the treasury stock method) or if Devon's Trust Convertible Preferred Securities were converted to common stock. Substantially all of Devon's Trust Convertible Preferred Securities were converted to common stock on November 30, 1999 (see Note 9).
The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and diluted net earnings per share for the year 1999. The diluted loss per share calculations for 1998 and 1997 produce results that are anti-dilutive. (The diluted calculation for 1998 reduced the net loss by $6.0 million and increased the common shares outstanding by 5.5 million shares. The 1997 diluted calculation reduced the net loss by $6.0 million and increased the common shares outstanding by 5.6 million shares.) Therefore, the diluted loss per share amounts for 1998 and 1997 reported in the accompanying consolidated statements of operations are the same as the basic loss per share amounts.
57

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                                      NET           WEIGHTED
                                                                                   EARNINGS          AVERAGE           NET
                                                                                  APPLICABLE         COMMON          EARNINGS
                                                                                   TO COMMON         SHARES            PER
                                                                                 STOCKHOLDERS      OUTSTANDING        SHARE
                                                                                 ------------      -----------       --------
                                                                                        (IN THOUSANDS)
Year ended December 31, 1999:

Basic earnings per share                                                             $90,905          60,015            $  1.51
                                                                                                                        =======

Dilutive effect of:
  Potential common shares issuable upon the conversion of Trust Convertible
  Preferred securities (the increase
  in net earnings is net of income tax expense of $2,742,000)                          4,289           4,485

  Potential common shares issuable upon the exercise of
  employee stock options                                                                  --             713
                                                                                     -------         -------

Diluted earnings per share                                                           $95,194          65,213            $  1.46
                                                                                     =======         =======            =======	

Options to purchase approximately 2.5 million shares of Devon's common stock, with exercise prices ranging from $36.28 per share to $92.78 per share (with a weighted average price of $52.74 per share), were excluded from the diluted earnings per share calculation for 1999. The excluded options for 1999 expire between April 26, 2000 and September 30, 2009. All options were excluded from the diluted earnings per share calculations for 1998 and 1997.
Comprehensive Earnings (Loss)
Devon adopted SFAS No. 130, "Reporting Comprehensive Income," on January 1, 1998. SFAS No. 130 was effective for fiscal years beginning after December 15, 1997. SFAS No. 130 established standards for reporting and display of comprehensive income and its components. Devon's comprehensive income information is included in the accompanying consolidated statements of stockholders' equity. A summary of accumulated other comprehensive loss as of December 31, 1999, 1998 and 1997, and changes during each of the years then ended, is presented in the following table.
58

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                 FOREIGN      MINIMUM
                                                CURRENCY       PENSION      UNREALIZED
                                               TRANSLATION    LIABILITY     LOSSES ON
                                                 ADJUST-       ADJUST-      MARKETABLE
                                                  MENTS         MENTS       SECURITIES       TOTAL
                                                ----------    ----------    ----------    ----------
                                                        (IN THOUSANDS)

Balance as of December 31, 1996                 $  (12,655)           --            --       (12,655)
     1997 activity                                 (14,458)           --            --       (14,458)
                                                ----------    ----------    ----------    ----------

Balance as of December 31, 1997                    (27,113)           --            --       (27,113)
     1998 activity                                  (8,130)       (1,179)           --        (9,309)
     Deferred taxes                                     --           460            --           460
                                                ----------    ----------    ----------    ----------
     1998 activity, net of deferred taxes           (8,130)         (719)           --        (8,849)
                                                ----------    ----------    ----------    ----------

Balance as of December 31, 1998                    (35,243)         (719)           --       (35,962)
     1999 activity                                   7,517          (394)      (62,059)      (54,936)
     Deferred taxes                                     --           153        24,203        24,356
                                                ----------    ----------    ----------    ----------
     1999 activity, net of deferred taxes            7,517          (241)      (37,856)      (30,580)
                                                ----------    ----------    ----------    ----------
Balance as of December 31, 1999                 $  (27,726)         (960)      (37,856)      (66,542)
                                                ==========    ==========    ==========    ==========	

Foreign Currency Translation Adjustments
The assets and liabilities of certain foreign subsidiaries are prepared in their respective local currencies and translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates, while income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive loss.
Dividends
Dividends on Devon's common stock were paid in 1999, 1998 and 1997 at a per share rate of $0.05 per quarter. As adjusted for the Northstar Combination's pooling-of-interests method of accounting, annual dividends per share for 1998 and 1997 were $0.15 and $0.14, respectively.
Statements of Cash Flows
For purposes of the consolidated statements of cash flows, Devon considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
59

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
Environmental expenditures are expensed or capitalized in accordance with generally accepted accounting principles. Liabilities for these expenditures are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Reference is made to Note 13 for a discussion of amounts recorded for these liabilities.
Reclassifications
Certain of the 1998 and 1997 amounts in the accompanying consolidated financial statements have been reclassified to conform to the 1999 presentation.
2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION
PennzEnergy Merger
Devon closed its merger with PennzEnergy Company ("PennzEnergy") on August 17, 1999. The merger was accounted for using the purchase method of accounting for business combinations. Accordingly, the accompanying statement of operations for 1999 includes the effects of PennzEnergy operations since August 17, 1999.
Devon issued approximately 21.5 million shares of its common stock to the former stockholders of PennzEnergy. In addition, Devon assumed long-term debt and other obligations totaling approximately $2.3 billion on August 17, 1999. The calculation of the total purchase price and the preliminary allocation to assets and liabilities as of August 17, 1999, are shown below. Devon intends to sell certain of the assets acquired. Generally, the proceeds from such sales will reduce the gross purchase price allocated to oil and gas properties.
60

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                                     (IN THOUSANDS,
                                                                                   EXCEPT SHARE PRICE)
Calculation and preliminary allocation of purchase price:
         Shares of Devon common stock issued to PennzEnergy
            stockholders                                                                   21,501
         Average Devon stock price                                                         $33.40
                                                                                      -----------
         Fair value of common stock issued                                            $   718,177
         Plus preferred stock assumed by Devon                                            150,000
         Plus estimated merger costs incurred                                              71,545
         Plus fair value of PennzEnergy employee stock options
            assumed by Devon                                                               18,295
         Less stock registration and issuance costs incurred                               (4,985)
                                                                                      -----------
Total purchase price                                                                      953,032

Plus fair value of liabilities assumed by Devon:
         Current liabilities                                                              200,708
         Debentures exchangeable into Chevron Corporation
            common stock                                                                  760,313
         Other long-term debt                                                             838,792
         Other long-term liabilities                                                      158,988
                                                                                       ----------
                                                                                        2,911,833
Less fair value of non oil and gas assets acquired by Devon:
         Current assets                                                                   109,769
         Non oil and gas properties                                                        31,412
         Investment in common stock of Chevron Corporation                                676,441
         Other assets                                                                      81,945
                                                                                      -----------
Fair value allocated to oil and gas properties, including $83.3
   million of undeveloped leasehold                                                    $2,012,266
                                                                                        =========	

Additionally, $338.9 million was added as goodwill for deferred taxes created as a result of the merger. Due to the tax-free nature of the merger, Devon's tax basis in the assets acquired and liabilities assumed are the same as PennzEnergy's tax basis. The $338.9 million of deferred taxes recorded represent the deferred tax effect of the differences between the fair values assigned by Devon for financial reporting purposes to the former PennzEnergy assets and liabilities and their bases for income tax purposes.
Estimated proved reserves added in the PennzEnergy merger were 232.7 million barrels of oil, 782.6 billion cubic feet of natural gas and 32.7 million barrels of natural gas liquids. Also, added in the PennzEnergy merger were approximately 13 million net acres of undeveloped leasehold. (The quantities of proved reserves stated in this paragraph are unaudited.)
Wascana Properties Transaction
On December 23, 1998, Devon acquired certain natural gas properties located in northeastern Alberta, Canada, from Wascana Oil and Gas Partnership, a subsidiary of Canadian Occidental Petroleums Ltd. (the "Wascana Properties"). Devon acquired the properties for
61

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
approximately $57.5 million, which was funded with bank debt under Devon's then existing credit facilities.
Estimated proved reserves of the Wascana Properties as of December 31, 1998, were 71.5 billion cubic feet of natural gas. Approximately $52.2 million of the purchase price was allocated to the proved reserves. The remaining $5.3 million of the purchase price was allocated to approximately 190,000 net undeveloped acres and exclusive rights to associated seismic data. (The quantities of proved reserves stated in this paragraph are unaudited.)
Pro Forma Information
Set forth in the following table is certain unaudited pro forma financial information for the years ended December 31, 1999 and 1998. This information has been prepared assuming the PennzEnergy merger and the Wascana Property transaction were consummated on January 1, 1998, and is based on estimates and assumptions deemed appropriate by Devon. The pro forma information is presented for illustrative purposes only. If the transactions had occurred in the past, Devon's operating results might have been different from those presented in the following table. The pro forma information should not be relied upon as an indication of the operating results that Devon would have achieved if the transactions had occurred on January 1, 1998. The pro forma information also should not be used as an indication of the future results that Devon will achieve after the transactions.
The pro forma information includes the effect of Devon's issuance of 10.3 million shares of common stock as if such shares had been issued on January 1, 1998. (See Note 10 for additional information on this issuance of shares of common stock.) The pro forma information assumes that the approximately $402 million of net proceeds from the issuance of common stock was used to retire long-term debt and therefore reduce interest expense.
The following should be considered in connection with the pro forma financial information presented:
o Expected annual cost savings of $50 to $60 million related to the PennzEnergy merger have not been reflected as an adjustment to the historical data in preparing the following pro forma information. These cost savings are expected to result from the consolidation of the corporate headquarters of Devon and PennzEnergy and the elimination of duplicate staff and expenses.
o The 1999 pro forma results include a gain of $46.7 million ($29.8 million after-tax) from PennzEnergy's pre-merger sale of land, timber and mineral rights in Pennsylvania and New York.
o In 1998, PennzEnergy realized pretax gains on the sale and exchange of Chevron Corporation common stock of $203.1 million. This gain is included in the 1998 pro forma financial information presented in the following table. The pro forma
62

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
financial information does not include the related $207.0 million after-tax extraordinary loss resulting from the early extinguishment of debt. The exclusion of the extraordinary loss from the 1998 pro forma results is required by Securities and Exchange Commission rules and regulations regarding presentation of pro forma results of operations, and is consistent with the pro forma results presented in the PennzEnergy merger proxy statement filed in 1999. If the extraordinary loss were included in the 1998 pro forma results, the 1998 pro forma net loss as presented in the following table would be $301 million, or $3.83 per share.
o The 1998 pro forma results include $24.3 million of nonrecurring general and administrative expenses in connection with the spin-off of Pennzoil-Quaker State Company on December 30, 1998.
o The 1998 pro forma results include a reduction of the carrying value of oil and gas properties incurred by Devon. This reduction, which was due to the full cost ceiling limitation, was $126.9 million ($88.0 million after-tax).
63

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                                PRO FORMA INFORMATION
                                                                               YEAR ENDED DECEMBER 31,
                                                                           ------------------------------
                                                                                1999              1998
                                                                      (DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES
    Oil sales                                                              $    389,977           302,918
    Gas sales                                                                   581,937           571,485
    Natural gas liquids sales                                                    82,229            63,726
    Other                                                                        85,153           295,803
                                                                           ------------      ------------
            Total revenues                                                    1,139,296         1,233,932
                                                                           ------------      ------------

COSTS AND EXPENSES
    Lease operating expenses                                                    262,955           297,217
    Production taxes                                                             32,006            28,148
    Depreciation, depletion and amortization of property
        and equipment                                                           470,265           488,608
    Amortization of goodwill                                                     46,321            52,637
    General and administrative expenses                                         109,328           139,378
    Northstar Combination expenses                                                   --            13,149
    Interest expense                                                            110,413           138,482
    Deferred effect of changes in foreign currency exchange rate on
        subsidiary's long-term debt                                             (13,154)           16,104
    Distributions on preferred securities of subsidiary trust                     6,884             9,717
    Reduction of carrying value of oil and gas properties                            --           126,900
                                                                           ------------      ------------
            Total costs and expenses                                          1,025,018         1,310,340
                                                                           ------------      ------------

Earnings (loss) before income tax expense and extraordinary item                114,278           (76,408)

INCOME TAX EXPENSE
    Current                                                                      24,661            10,324
    Deferred                                                                     31,527             7,278
                                                                           ------------      ------------
        Total income tax expense                                                 56,188            17,602
                                                                           ------------      ------------

Earnings (loss) before extraordinary item                                        58,090           (94,010)

Preferred stock dividends                                                         9,736             5,625
                                                                           ------------      ------------
Earnings (loss) before extraordinary item applicable to
    common stockholders                                                    $     48,354           (99,635)
                                                                           ============      ============
Earnings (loss) before extraordinary item per average common
    share outstanding - basic and diluted                                  $       0.60             (1.24)
                                                                           ============      ============

Weighted average common shares outstanding - basic                               81,070            80,061
                                                                           ============      ============

PRODUCTION DATA
    Oil (MBbls)                                                                  24,092            26,128
    Gas (MMcf)                                                                  300,779           319,930
    Natural gas liquids (MBbls)                                                   6,908             7,129
    MBoe                                                                         81,130            86,579	

64

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Northstar Combination
On June 29, 1998, Devon and Northstar Energy Corporation ("Northstar") announced they had entered into a definitive combination agreement subject to shareholder approval and certain other conditions. The combination of the two companies (the "Northstar Combination") was closed on December 10, 1998. At that date, Northstar became a wholly-owned subsidiary of Devon. Pursuant to the Northstar Combination, Northstar's common shareholders received approximately 16.1 million exchangeable shares (the "Exchangeable Shares") based on an exchange ratio of 0.235 Exchangeable Shares for each Northstar common share outstanding. The Exchangeable Shares were issued by Northstar, but are exchangeable at any time into Devon's common shares on a one-for-one basis. Prior to such exchange, the Exchangeable Shares have rights identical to those of Devon's common shares, including dividend, voting and liquidation rights. Between December 10, 1998 and December 31, 1999, approximately 11.4 million of the originally issued 16.1 million Exchangeable Shares had been exchanged for shares of Devon common stock.
The Northstar Combination was accounted for under the pooling-of-interests method of accounting for business combinations. All operational and financial information contained herein includes the combined amounts for Devon and Northstar for all periods presented.
During the fourth quarter of 1998, Devon recorded a pre-tax charge of $13.1 million ($9.7 million after tax) for direct costs related to the Northstar Combination.
Morrison Transaction
In March 1997, Northstar acquired all the outstanding common shares of Morrison Petroleums Ltd. ("Morrison"), an independent oil and gas producer also located in Alberta, Canada. Northstar acquired the Morrison common shares by issuing common shares of Northstar (the "Morrison Transaction"). The Northstar common shares received by the Morrison shareholders represented approximately 53% of the combined company's outstanding shares. Therefore, this transaction was accounted for as a reverse acquisition under U.S. generally accepted accounting principles. Accordingly, Northstar's results through March 31, 1997, which are combined with Devon's results in the accompanying consolidated financial statements, represent the historical results of Morrison, the "accounting acquirer." Because Northstar was the "legal acquirer," the financial results and other information for periods through March 31, 1997, are referred to as "Northstar's" results and information, even though they represent the historical results of Morrison. For periods subsequent to March 31, 1997, Northstar's results that are combined with Devon's results represent the historical results of Morrison, combined with Northstar's results after valuing Northstar's March 31, 1997, assets and liabilities at fair value, rather than historical book value.
The estimated proved reserves added in the Morrison Transaction were 18.3 million barrels of oil, 213.5 billion cubic feet of natural gas and 2.9 million barrels of natural gas liquids.
65

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Also added in the Morrison Transaction were approximately 563,000 net acres of undeveloped leasehold. (The quantities of proved reserves stated in this paragraph are unaudited.)
After giving effect to the Northstar Combination exchange ratio of 0.235, approximately 9.8 million Exchangeable Shares are deemed to have been issued in the Morrison Transaction with a total value of approximately $441.6 million. Also, approximately $111.3 million of liabilities were assumed and $128.5 million of additional deferred tax liabilities were recorded due to the tax-free nature of the Morrison Transaction to the Morrison shareholders. Excluding the $128.5 million of additional deferred tax liabilities, the total purchase price was allocated $435.2 million to proved oil and gas reserves, $37.3 million to undeveloped leasehold and $80.4 million to other assets acquired. Including the $128.5 million of deferred tax liabilities, the allocation was $527.9 million to proved oil and gas reserves, $43.5 million to undeveloped leasehold and $110.0 million to other assets.
3. SAN JUAN BASIN TRANSACTION
At the beginning of 1995, Devon entered into a transaction (the "San Juan Basin Transaction") involving a volumetric production payment and repurchase option. The San Juan Basin Transaction allowed Devon to monetize tax credits earned from certain of its coal seam gas production in the San Juan Basin. During 1999, 1998 and 1997, the San Juan Basin Transaction added approximately $7.6 million, $8.4 million and $8.5 million, respectively, to Devon's gas revenues.
Under the terms of the San Juan Basin Transaction, Devon has a repurchase option which it can exercise at anytime. Devon records a portion of the quarterly cash payments received pursuant to the San Juan Basin Transaction as a repurchase liability based upon the estimated eventual repurchase price. Devon has also received cash payments in exchange for agreeing not to exercise its repurchase option for specific periods of time. These payments have also been added to the repurchase liability. As a result, in addition to the cash flow recorded as revenues described in the previous paragraph, Devon also received $16.6 million, $6.8 million and $6.2 million in 1999, 1998 and 1997, respectively, which was added to the repurchase liability. At December 31, 1999, the repurchase liability totaled $37.6 million. This amount is included in other long-term liabilities in Devon's consolidated balance sheet.
The additional gas revenues generated by the San Juan Basin Transaction will continue until December 31, 2002, unless Devon exercises its repurchase option earlier.
4. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments for interest in 1999, 1998 and 1997 were approximately $63.3 million, $24.5 million and $16.7 million, respectively. Cash payments for federal, state and foreign income taxes in 1999, 1998 and 1997 were approximately $10.8 million, $14.2 million and $26.9 million, respectively.
66

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The 1999 PennzEnergy merger and the 1997 Morrison Transaction involved non-cash consideration as presented below:

                                                           1999             1997
                                                       ------------     ------------
                                                               (IN THOUSANDS)
Value of common stock issued                           $    718,177          441,590
Value of preferred stock issued                             150,000               --
Employee stock options assumed                               18,295               --
Liabilities assumed                                       1,958,801          111,345
Deferred tax liability created                              338,911          128,497
                                                       ------------     ------------

Fair value of assets acquired with
   non-cash consideration                              $  3,184,184          681,432
                                                       ============     ============	

During the fourth quarter of 1999, substantially all of the 6.5% Trust Convertible Preferred Securities were converted to Devon common stock (see Note 9).
5. ACCOUNTS RECEIVABLE
The components of accounts receivable included the following:

                                                          DECEMBER 31,
                                          ------------------------------------------
                                             1999            1998            1997
                                          ----------      ----------      ----------
                                                        (IN THOUSANDS)
Oil, gas and natural gas liquids
    revenue accruals                      $  138,562          46,360          52,974
Joint interest billings                       54,158          23,636          25,283
Other                                         18,285          14,262          19,398
                                          ----------      ----------      ----------
                                             211,005          84,258          97,655
Allowance for doubtful accounts               (1,600)           (400)           (827)
                                          ----------      ----------      ----------

Net accounts receivable                   $  209,405          83,858          96,828
                                          ==========      ==========      ==========	

67

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
6. PROPERTY AND EQUIPMENT
Property and equipment included the following:

                                                                       `                DECEMBER 31,
                                                                              1999          1998            1997
                                                                          -----------    -----------    -----------
                                                                                       (IN THOUSANDS)
Oil and gas properties:
    Subject to amortization                                               $ 4,589,986      2,413,376      2,157,104
Not subject to amortization:
       Acquired in 1999                                                       115,866             --             --
       Acquired in 1998                                                        37,522         46,302             --
       Acquired in 1997                                                        36,077         51,961         60,399
       Acquired prior to 1997                                                  57,620         63,414         70,348
    Accumulated depreciation, depletion
       and amortization                                                    (1,800,424)    (1,498,075)    (1,316,343)
                                                                          -----------    -----------    -----------

           Net oil and gas properties                                       3,036,647      1,076,978        971,508
                                                                          -----------    -----------    -----------

Other property and equipment                                                  137,739         35,458         32,884

Accumulated depreciation and amortization                                     (18,466)       (11,508)        (9,109)
                                                                          -----------    -----------    -----------

           Net other property and equipment                                   119,273         23,950         23,775
                                                                          -----------    -----------    -----------

Property and equipment, net of
    accumulated depreciation,
    depletion and amortization                                            $ 3,155,920      1,100,928        995,283
                                                                          ===========    ===========    ===========	

Depreciation, depletion and amortization of property and equipment consisted of the following components:

                                                                                          YEAR ENDED DECEMBER 31,
                                                                                      1999         1998         1997
                                                                                   ----------   ----------   ----------
                                                                                              (IN THOUSANDS)
Depreciation, depletion and amortization
  of oil and gas properties                                                        $  244,517      119,719      164,977
Depreciation and amortization of other
  property and equipment                                                                7,160        3,964        3,566
Amortization of other assets                                                            2,598          161          565
                                                                                   ----------   ----------   ----------

    Total expense                                                                  $  254,275      123,844      169,108
                                                                                   ==========   ==========   ==========	

68

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
7. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:

                                                                          DECEMBER 31,
                                                     -----------------------------------------------------
                                                               1999
                                                     -------------------------
                                                     PRO FORMA(A)     ACTUAL         1998          1997
                                                     -----------   -----------   -----------   -----------
                                                                         (IN THOUSANDS)
Borrowings under credit facilities with banks        $   414,341       314,341       180,271       219,316
Debentures exchangeable into shares of Chevron
   Corporation common stock:
     4.90% due August 15, 2008                           443,807       443,807            --            --
     4.95% due August 15, 2008                           316,506       316,506            --            --
Other debentures:
     10.25% due November 1, 2005                         250,000       250,000            --            --
     10.125% due November 15, 2009                       200,000       200,000            --            --
     Premium on debentures                                37,467        37,467            --            --
Senior notes:
     6.76% due July 19, 2005                                  --        75,000        75,000        75,000
     6.79% due March 2, 2009                                  --       150,000       150,000            --
     7.03% due November 7, 2005                               --            --            --        60,000
                                                     -----------   -----------   -----------   -----------
                                                       1,662,121     1,787,121       405,271       354,316
Less amount classified as current                             --            --            --        48,979
                                                     -----------   -----------   -----------   -----------

Long-term debt                                       $ 1,662,121     1,787,121       405,271       305,337
                                                     ===========   ===========   ===========   ===========	

Maturities of long-term debt as of December 31, 1999, excluding the $37.5 million of premiums, are as follows (in thousands):

                         PRO FORMA(a)     ACTUAL
                         ------------    ---------
 2000                    $         --           --
 2001                           9,467       20,717
 2002                          84,467       20,717
 2003                           9,467       20,717
 2004                         159,467      220,717
 2005 and thereafter        1,361,786    1,466,786
                         ------------    ---------

Total                    $  1,624,654    1,749,654
                         ============   ==========	

(a) A discussion of pro forma debt outstanding is included later in this note.
69

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Credit Facilities With Banks
On October 15, 1999, Devon entered into new unsecured long-term credit facilities aggregating $750 million (the "Credit Facilities"). The Credit Facilities include a U.S. facility of $475 million (the "U.S. Facility") and a Canadian facility of $275 million (the "Canadian Facility"). The Credit Facilities replaced Devon's previous facilities that totaled $400 million.
The $475 million U.S. Facility consists of a Tranche A facility of $200 million and a Tranche B facility of $275 million. The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until October 13, 2000 (the "Tranche B Revolving Period"). Devon may request that the Tranche B Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 30 and 60 days prior to the end of the Tranche B Revolving Period. Debt borrowed under the Tranche B facility matures two years and one day following the end of the Tranche B Revolving Period. At December 31, 1999, there were $200 million in borrowings from the $475 million U.S. Facility, all of which was borrowed under the Tranche A facility.
Devon may borrow funds under the $275 million Canadian Facility until October 13, 2000 (the "Canadian Facility Revolving Period"). Devon may request that the Canadian Facility Revolving Period be extended an additional 364 days by notifying the agent bank of such request between 45 and 90 days prior to the end of the Canadian Facility Revolving Period. Debt outstanding as of the end of the Canadian Facility Revolving Period is payable in semi-annual installments of 2.5% each for the following five years, with the final installment due five years and one day following the end of the Canadian Facility Revolving Period. At December 31, 1999, there was $114.3 million borrowed under the $275 million Canadian facility.
Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods up to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit Facilities provide for an annual facility fee of $0.9 million that is payable quarterly. The average interest rate on the $314.3 million of debt outstanding at December 31, 1999, was 5.9%. The average interest rate on bank debt outstanding under the previous facilities at December 31, 1998 and 1997 was 5.9% and 4.8%, respectively.
The agreements governing the Credit Facilities contain certain covenants and restrictions, including a maximum debt-to-capitalization ratio. At December 31, 1999, Devon was in compliance with such covenants and restrictions.
Exchangeable Debentures
The exchangeable debentures consist of $443.8 million of 4.90% debentures and $316.5 million of 4.95% debentures. The exchangeable debentures were issued on August 3, 1998, mature August 15, 2008, and are callable beginning August 15, 2000. The exchangeable
70

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
debentures are exchangeable at the option of the holders at any time prior to maturity, unless previously redeemed, for shares of Chevron Corporation common stock. In lieu of delivering Chevron Corporation common stock, Devon may, at its option, pay to any holder an amount of cash equal to the market value of the Chevron Corporation common stock to satisfy the exchange request. However, at maturity, the holders will receive an amount at least equal to the face value of the debt outstanding - either in cash or in a combination of cash and Chevron Corporation common stock.
As of December 31, 1999, Devon beneficially owned approximately 7.1 million shares of Chevron Corporation common stock. These shares have been deposited with an exchange agent for possible exchange for the exchangeable debentures. Each $1,000 principal amount of the exchangeable debentures is exchangeable into 9.3283 shares of Chevron Corporation common stock, an exchange rate equivalent to $107 7/32 per share of Chevron stock.
The exchangeable debentures were assumed as part of the PennzEnergy merger. The fair values of the exchangeable debentures were determined as of August 17, 1999, based on market quotations. The fair value approximated the face value of the exchangeable debentures. As a result, no premium or discount was recorded on these exchangeable debentures.
Other Debentures
The 10.25% and 10.125% debentures were assumed as part of the PennzEnergy merger. The fair values of the respective debentures were determined using August 17, 1999, market interest rates. As a result, premiums were recorded on these debentures which lowered their effective interest rates to 8.3% and 8.9% on the $250 million of 10.25% debentures and $200 million of 10.125% debentures, respectively. The premiums are being amortized using the effective interest method.
Senior Notes
Northstar issued the 6.76% notes in a private placement in 1995. The notes were unsecured and were payable in five annual installments of $15 million each beginning in 2001. In mid-January 2000, Devon retired these notes. See the "Pro Forma" section below.
Northstar issued the 6.79% notes in a private placement in 1998. The notes were unsecured and were payable in three annual installments of $50 million each beginning in 2007. Proceeds from these notes were partially used to retire the $60 million of 7.03% notes referred to in the preceding table of long-term debt. In mid-January 2000, Devon retired these notes. See the "Pro Forma" section below.
The agreements governing the Senior Notes contained certain covenants and restrictions specific to Northstar, including maintenance of certain debt-to-capitalization and debt-to-EBITDA ratios and a minimum tangible net worth as well as restrictions on additional
71

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
borrowings. At December 31, 1999, Northstar was in compliance with such covenants and restrictions.
Pro Forma
In January 2000, Devon used excess cash of $75 million, together with borrowings of $150 million under its Credit Facilities, to retire the $225 million of Senior Notes outstanding as of December 31, 1999. Also in January 2000, Devon used an additional $50 million of excess cash to pay down borrowings under Tranche A of the U.S. Facility. The result of these early 2000 transactions left $414.3 million outstanding under the Credit Facilities. Of this amount, $150 million was borrowed under Tranche A of the U.S. Facility, $75 million was borrowed under Tranche B of the U.S. Facility and $189.3 million was borrowed under the Canadian Facility. The average interest rate on the $414.3 million of pro forma debt outstanding under the Credit Facilities was 5.9%.
Interest Expense
Following are the components of interest expense for the years 1999, 1998 and 1997:

                                                    1999          1998         1997
                                                 ----------    ----------    ----------
                                                             (IN THOUSANDS)

Interest based on debt outstanding               $   66,164        21,814        14,345
Amortization of premium on debentures                (1,328)           --            --
Facility and agency fees                                930           632           598
Amortization of capitalized loan costs                  783           156           118
Penalty on early retirement of debt                      --            --         3,323
Hedging gains                                            --          (188)         (410)
Other                                                   364           218           814
                                                 ----------    ----------    ----------

Total interest expense                           $   66,913        22,632        18,788
                                                 ==========    ==========    ==========	

Deferred Effect of Changes in Foreign Currency Exchange Rate on Long-term Debt
The fixed-rate Senior Notes referred to in the first table of this note were payable by Northstar. However, the notes were denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar from the dates the notes were issued to the dates of repayment increased or decreased the expected amount of Canadian dollars eventually required to repay the notes. Such changes in the Canadian dollar equivalent of the debt were required to be included in determining net earnings for the period in which the exchange rate changed. The rate of conversion of Canadian dollars to U.S. dollars increased in 1999 and declined in 1998 and 1997. Therefore, $13.2 million of reduced expense was recorded in 1999, and $16.1 million and $5.9 million of increased expenses were recorded in 1998 and 1997, respectively.
72

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
8. INCOME TAXES
At December 31, 1999, Devon had the following carryforwards available to reduce future income taxes:

                                                            YEARS OF        CARRYFORWARD
TYPES OF CARRYFORWARD                                      EXPIRATION         AMOUNTS
                                                           ----------      -------------
                                                                           (IN THOUSANDS)
Net operating loss - U.S. federal                         2008 - 2014          $309,098
Net operating loss - various states                       2000 - 2013          $157,801
Net operating loss - Canada                               2000 - 2005         $  85,254
Minimum tax credits                                        Indefinite         $  69,647	

All of the carryforward amounts shown above have been utilized for financial purposes to reduce deferred taxes.
The earnings (loss) before income taxes and the components of income tax expense (benefit) for the years 1999, 1998 and 1997 were as follows:

                                                         YEAR ENDED DECEMBER 31,
                                                   1999          1998          1997
                                                ----------    ----------    ----------
                                                             (IN THOUSANDS)
Earnings (loss) before income taxes:
   U.S                                          $  103,399       (95,750)      106,665
   Canada                                           57,402        19,958      (580,498)
   Other                                            (1,079)           --            --
                                                ----------    ----------    ----------
   Total                                        $  159,722       (75,792)     (473,833)
                                                ==========    ==========    ==========
Current income tax expense:
   U.S. federal                                     18,844         4,801        18,659
   Various states                                    2,904           911         2,521
   Canada                                            2,908         1,975         5,677
   Other                                                --            --            --
                                                ----------    ----------    ----------
   Total current tax expense                        24,656         7,687        26,857
                                                ----------    ----------    ----------
Deferred income tax expense (benefit):
   U.S. federal                                     14,514       (29,524)       17,025
   Various states                                     (495)       (4,836)        1,578
   Canada                                           26,654        11,166      (219,302)
   Other                                              (163)           --            --
                                                ----------    ----------    ----------
   Total deferred tax expense (benefit)             40,510       (23,194)     (200,699)
                                                ----------    ----------    ----------
Total income tax expense (benefit)                $ 65,166       (15,507)     (173,842)
                                                ==========    ==========    ==========	

73

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings (loss) before income taxes as a result of the following:

                                                      YEAR ENDED DECEMBER 31,
                                                     -------------------------
                                                     1999      1998      1997
                                                     ----      ----      ----
U.S. statutory tax (benefit) rate                       35%      (35)%     (35)%
Non-deductible expenses                                  3        15        --
Nonconventional fuel source credits                     (3)       (4)       --
State income taxes                                       1        (3)       --
Taxation on foreign operations                           6         8        (2)
Other                                                   (1)       (1)       --
                                                      ----      ----      ----
Effective income tax (benefit) rate                     41%      (20)%     (37)%
                                                      ====      ====      ====	

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at December 31, 1999, 1998 and 1997 are presented below:

                                                            DECEMBER 31,
                                                ------------------------------------
                                                   1999         1998         1997
                                                ----------   ----------   ----------
                                                           (IN THOUSANDS)
Deferred tax assets:
   Net operating loss carryforwards             $  156,622       21,818       21,076
   Minimum tax credit carryforwards                 69,647           --           --
   Production payments                              21,527       19,105       18,504
   Long-term debt                                   17,583           --           --
   Other                                            45,018        3,188        7,173
                                                ----------   ----------   ----------
      Total gross deferred tax assets              310,397       44,111       46,753
      Less valuation allowance                         100          100          100
                                                ----------   ----------   ----------
      Net deferred tax assets                      310,297       44,011       46,653
                                                ----------   ----------   ----------
Deferred tax liabilities:
   Property and equipment, principally due
      to differences in depreciation, and
      the expensing of intangible drilling
      costs for tax purposes                      (492,756)     (76,156)     (76,523)
   Chevron Corporation common stock               (172,631)          --           --
   Other                                           (30,889)        (469)      (1,521)
                                                ----------   ----------   ----------
   Total deferred tax liabilities                 (696,276)     (76,625)     (78,044)
                                                ----------   ----------   ----------

         Net deferred tax liability             $ (385,979)     (32,614)     (31,391)
                                                ==========   ==========   ==========	

As shown in the above schedule, Devon has recognized $310.3 million of net deferred tax assets as of December 31, 1999. Such amount consists primarily of $226.3 million of various
74

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
carryforwards available to offset future income taxes. The carryforwards include federal net operating loss carryforwards, the majority of which do not begin to expire until 2008, state net operating loss carryforwards which expire primarily between 2000 and 2013, Canadian carryforwards which expire primarily between 2000 and 2005, and minimum tax credit carryforwards which have no expiration. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be "more likely than not." When the future utilization of some portion of the carryforwards is determined not to be "more likely than not," a valuation allowance is provided to reduce the recorded tax benefits from such assets.
Devon expects the tax benefits from the net operating loss carryforwards to be utilized between 2000 and 2006. Such expectation is based upon current estimates of taxable income during this period, considering limitations on the annual utilization of these benefits as set forth by federal tax regulations. Significant changes in such estimates caused by variables such as future oil and gas prices or capital expenditures could alter the timing of the eventual utilization of such carryforwards. There can be no assurance that Devon will generate any specific level of continuing taxable earnings. However, management believes that Devon's future taxable income will more likely than not be sufficient to utilize substantially all its tax carryforwards prior to their expiration. A $0.1 million valuation allowance has been recorded at December 31, 1999, related to depletion carryforwards acquired in a 1994 merger.
The $21.5 million of deferred tax assets related to production payments is offset by a portion of the deferred tax liability related to the excess financial basis of property and equipment. The income tax accounting for the San Juan Basin Transaction described in Note 3 differs from the financial accounting treatment. For income tax purposes, a gain from the conveyance of the properties was realized, and the present value of the production payments to be received was recorded as a note receivable. For presentation purposes, the $21.5 million represents the tax effect of the difference in accounting for the production payment, less the effect of the taxable gain from the transaction which is being deferred and recognized on the installment basis for income tax purposes.
9. TRUST CONVERTIBLE PREFERRED SECURITIES
On July 10, 1996, Devon, through its affiliate Devon Financing Trust, completed the issuance of $149.5 million of 6.5% trust convertible preferred securities (the "TCP Securities"). Devon Financing Trust issued 2,990,000 shares of the TCP Securities at $50 per share with a maturity date of June 15, 2026. Each TCP Security was convertible at the holder's option into 1.6393 shares of Devon common stock, which equates to a conversion price of $30.50 per share of Devon common stock.
Devon Financing Trust invested the $149.5 million of proceeds in 6.5% convertible junior subordinated debentures issued by Devon (the "Convertible Debentures"). In turn, Devon used the net proceeds from the issuance of the Convertible Debentures to retire debt outstanding under its credit lines.
On October 27, 1999, Devon issued notice to the holders of the TCP Securities that it was
75

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
exercising its right to redeem such securities on November 30, 1999. Substantially all of the holders of the TCP Securities elected to exercise their conversion rights instead of receiving the redemption cash value. As a result, all but 950 shares of the TCP Securities were converted into approximately 4.9 million shares of Devon common stock. The redemption price for the 950 shares not converted was $52.275 per share, or $50,000 total, which included a 4.55% premium as required under the terms of the TCP Securities.
Devon owned all the common securities of Devon Financing Trust. As such, the accounts of Devon Financing Trust were included in Devon's consolidated financial statements after appropriate eliminations of intercompany balances and transactions. The distributions on the TCP Securities were recorded as a charge to pre-tax earnings on Devon's consolidated statements of operations, and such distributions were deductible by Devon for income tax purposes.
10. STOCKHOLDERS' EQUITY
The authorized capital stock of Devon consists of 400 million shares of common stock, par value $.10 per share (the "Common Stock"), and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one or more series, and the terms and rights of such stock will be determined by the Board of Directors.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49% cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative preferred stock, Series A. Dividends on the preferred stock are cumulative from the date of original issue and are payable quarterly, in cash, when declared by the Board of Directors. The preferred stock is redeemable at the option of Devon at any time on or after June 2, 2008, in whole or in part, at a redemption price of $100 per share, plus accrued and unpaid dividends to the redemption date.
In late September and early October 1999, Devon received $402.7 million from the sale of approximately 10.3 million shares of its common stock in a public offering. The price to the public for these shares was $40.50 per share. Net of underwriters' discount and commissions, Devon received $38.98 per share. Devon paid approximately $0.8 million of expenses related to the equity offering, and these costs were recorded as reductions of additional paid-in capital.
As discussed in Note 2, there were approximately 21.5 million shares of Devon common stock issued on August 17, 1999, in connection with the PennzEnergy merger. Also, as discussed in Note 2, there were 16.1 million Exchangeable Shares issued on December 10, 1998, in connection with the Northstar Combination. As of year-end 1999, 11.4 million of the Exchangeable Shares had been exchanged for shares of Devon's common stock. The Exchangeable Shares have rights identical to those of Devon's common stock and are exchangeable at any time into Devon's common stock on a one-for-one basis.
Devon's Board of Directors has designated 1.0 million shares of the preferred stock as Series A Junior Participating Preferred Stock (the "Series A Junior Preferred Stock") in connection with the
76

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
adoption of the share rights plan described later in this note. At December 31, 1999, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $10 or 100 times the aggregate per share amount of all dividends (other than stock dividends) declared on Common Stock since the immediately preceding quarterly dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock. Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share (subject to adjustment to prevent dilution) on all matters submitted to a vote of the stockholders. The Series A Junior Preferred Stock is neither redeemable nor convertible. The Series A Junior Preferred Stock ranks prior to the Common Stock but junior to all other classes of Preferred Stock.
Stock Option Plans
Devon has outstanding stock options issued to key management and professional employees under three stock option plans adopted in 1988, 1993 and 1997 (the "1988 Plan," the "1993 Plan" and the "1997 Plan"). Options granted under the 1988 Plan and 1993 Plan remain exercisable by the employees owning such options, but no new options will be granted under these plans. At December 31, 1999, there were 189,000 and 740,500 options outstanding under the 1988 Plan and the 1993 Plan, respectively.
On May 21, 1997, Devon's stockholders adopted the 1997 Plan and reserved two million shares of Common Stock for issuance thereunder. On December 9, 1998, Devon's stockholders voted to increase the reserved shares to three million. On August 17, 1999, Devon's stockholders voted to increase the reserved shares to six million.
The exercise price of stock options granted under the 1997 Plan may not be less than the estimated fair market value of the stock at the date of grant, plus 10% if the grantee owns or controls more than 10% of the total voting stock of Devon prior to the grant. Options granted are exercisable during a period established for each grant, which period may not exceed 10 years from the date of grant. Under the 1997 Plan, the grantee must pay the exercise price in cash or in Common Stock, or a combination thereof, at the time that the option is exercised. The 1997 Plan is administered by a committee comprised of non-management members of the Board of Directors. The 1997 Plan expires on April 25, 2007. As of December 31, 1999, there were 2,142,150 options outstanding under the 1997 Plan. There were 3,725,550 options available for future grants as of December 31, 1999.
In addition to the stock options outstanding under the 1988 Plan, 1993 Plan and 1997 Plan, there were 2,081,124 and 226,571 stock options outstanding at the end of 1999 that were assumed as part of the PennzEnergy merger and the Northstar Combination, respectively. PennzEnergy and Northstar had granted these options prior to the PennzEnergy merger and the Northstar Combination. As part of the PennzEnergy merger and the Northstar Combination, the options were assumed by Devon and converted to Devon options at the exchange rate of 0.4475 and 0.235 Devon options for each PennzEnergy and Northstar option, respectively.
77

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
A summary of the status of Devon's stock option plans as of December 31, 1997, 1998 and 1999, and changes during each of the years then ended, is presented below.

                                            OPTIONS OUTSTANDING          OPTIONS EXERCISABLE
                                      ----------------------------   ---------------------------
                                                                      WEIGHTED         WEIGHTED
                                                                       AVERAGE         AVERAGE
                                         NUMBER        EXERCISE        NUMBER          EXERCISE
                                       OUTSTANDING       PRICE       EXERCISABLE        PRICE
                                      ------------    ------------   ------------   ------------
Balance at December 31, 1996             2,025,783    $     27.305      1,112,049   $     24.556
                                                                     ============   ============
    Options assumed in the
      Morrison Transaction                 732,041    $     36.260
    Options granted                        691,767    $     32.515
    Options exercised                     (486,918)   $     26.444
    Options forfeited                     (332,183)   $     37.540
                                      ------------

Balance at December 31, 1997             2,630,490    $     29.276      1,415,909   $     26.483
                                                                      ============   ============
    Options granted                      1,260,397    $     31.230
    Options exercised                     (134,295)   $     21.087
    Options forfeited                     (300,900)   $     32.730
                                      ------------

Balance at December 31, 1998             3,455,692    $     28.995      2,635,727   $     28.793
                                                                     ============   ============
    Options granted                      1,148,000    $     30.817
    Options assumed in the
      PennzEnergy merger                 2,081,894    $     55.643
    Options exercised                     (924,467)   $     27.392
    Options forfeited                     (381,774)   $     34.841
                                      ------------

Balance at December 31, 1999             5,379,345    $     39.555      4,185,547   $     42.020
                                      ============                   ============   ============	

The weighted average fair values of options granted during 1999, 1998 and 1997 were $10.23, $10.72 and $10.12, respectively. The fair value of each option grant was estimated for disclosure purposes on the date of grant using the Black-Scholes Option Pricing Model with the following assumptions for 1999, 1998 and 1997, respectively: risk-free interest rates of 6.0%, 4.9% and 6.0%; dividend yields of 0.6%, 0.5% and 0.1%; expected lives of 4, 4 and 4 years; and volatility of the price of the underlying common stock of 34.2%, 33.9% and 30.7%.
78

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The following table summarizes information about Devon's stock options which were outstanding, and those which were exercisable, as of December 31, 1999:

                                  OPTIONS OUTSTANDING                OPTIONS EXERCISABLE
                       ---------------------------------------    ------------------------
                                        WEIGHTED     WEIGHTED                     WEIGHTED
  RANGE OF                               AVERAGE     AVERAGE                      AVERAGE
  EXERCISE               NUMBER        REMAINING     EXERCISE       NUMBER        EXERCISE
   PRICES              OUTSTANDING        LIFE         PRICE      EXERCISABLE      PRICE
--------------         -----------     ---------    ----------    -----------   ----------
$ 8.375-$25.440            717,466     4.4 years    $   21.773       702,600    $   21.713
$26.291-$29.850            734,622     5.5 years    $   29.001       616,064    $   28.977
$30.938-$33.606          1,441,919     8.9 years    $   31.257       410,378    $   31.843
$35.582-$39.437            977,694     8.1 years    $   36.875       950,411    $   36.863
$40.125-$58.840            813,250     6.0 years    $   52.868       811,700    $   52.891
$63.433-$92.781            694,394     5.2 years    $   74.504       694,394    $   74.504
                        ----------                                ----------
                         5,379,345     6.8 years    $   39.555     4,185,547    $   42.020
                         ==========                               ==========	

Had Devon elected the fair value provisions of SFAS No. 123 and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, Devon's 1999, 1998 and 1997 pro forma net earnings (loss) and pro forma net earnings (loss) per share would have differed from the amounts actually reported as shown in the following table. The pro forma amounts shown below do not include the effects of stock options granted prior to January 1, 1995.

                                                                                 YEAR ENDED DECEMBER 31,
                                                                           -------------------------------------
                                                                           1999            1998           1997
                                                                           ----            ----           ----
                                                                        (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Net earnings (loss) available to common shareholders:
         As reported                                                   $   90,905        (60,285)       (299,991)
         Pro forma                                                     $   84,095        (72,770)       (306,992)

Net earnings (loss) per share available to common shareholders:
         As reported:
                  Basic                                                $     1.51          (1.25)          (6.38)
                  Diluted                                              $     1.46          (1.25)          (6.38)
         Pro forma:
                  Basic                                                $     1.40          (1.50)          (6.52)
                  Diluted                                              $     1.36          (1.50)          (6.52)	

79

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Share Rights Plan
Under Devon's share rights plan, stockholders have one right for each share of Common Stock held. The rights become exercisable and separately transferable ten business days after a) an announcement that a person has acquired, or obtained the right to acquire, 15% or more of the voting shares outstanding, or b) commencement of a tender or exchange offer that could result in a person owning 15% or more of the voting shares outstanding.
Each right entitles its holder (except a holder who is the acquiring person) to purchase either a) 1/100 of a share of Series A Preferred Stock for $75.00, subject to adjustment or b) Devon Common Stock with a value equal to twice the exercise price of the right, subject to adjustment to prevent dilution. In the event of certain merger or asset sale transactions with another party or transactions which would increase the equity ownership of a shareholder who then owned 15% or more of Devon, each Devon right will entitle its holder to purchase securities of the merging or acquiring party with a value equal to twice the exercise price of the right.
The rights, which have no voting power, expire on April 16, 2005. The rights may be redeemed by Devon for $.01 per right until the rights become exercisable.
11. FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values of Devon's financial instruments at December 31, 1999, 1998 and 1997.

                                                         1999                         1998                       1997
                                              --------------------------      ---------------------     ------------------------
                                                CARRYING         FAIR         CARRYING       FAIR       CARRYING         FAIR
                                                AMOUNT           VALUE         AMOUNT        VALUE       AMOUNT          VALUE
                                              ----------      ----------      --------     --------     ---------      ---------
                                                                               (IN THOUSANDS)

Investments                                   $   625,181        625,181         1,930         1,930        2,409          5,125
Oil and gas price hedge agreements            $        --        (11,525)           --         1,988           --          3,569
Foreign exchange hedge agreements             $        --         (2,535)           --        (9,310)          --         (5,038)
Long-term debt (including current portion)    $(1,787,121)    (1,772,934)     (405,271)     (421,675)    (354,316)      (360,294)
TCP Securities                                $        --             --      (149,500)     (171,400)    (149,500)      (218,800)	

The following methods and assumptions were used to estimate the fair values of the financial instruments in the above table. None of Devon's financial instruments are held for trading purposes. The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at December 31, 1999, 1998 and 1997.
80

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Investments - The fair values of investments are primarily based on quoted market prices.
Oil and Gas Price Hedge Agreements - The fair values of the oil and gas price hedges are based on either (a) quotes obtained from the counterparty to the hedge agreement or (b) quotes provided by brokers.
Foreign Exchange Hedge Agreements - The fair values of the foreign exchange agreements are based on quotes obtained from brokers.
Long-term Debt - The fair values of the fixed-rate long-term debt have been estimated based on quotes obtained from brokers or by discounting the principal and interest payments at rates available for debt of similar terms and maturity. The fair values of the floating-rate long-term debt are estimated to approximate the carrying amounts due to the fact that the interest rates paid on such debt are generally set for periods of three months or less.
TCP Securities - The fair values of the TCP Securities are based on quoted market prices provided by brokers.
The following table covers Devon's notional volumes and pricing on open natural gas hedging instruments as of December 31, 1999:

                                                                      YEAR OF PRODUCTION
                                                              ---------------------------------
                                                               2000         2001           2002
                                                              ------       ------         -----
Volumes (billion British thermal units)                       18,215       12,661         2,656
Average price to be received                                  $1.82         1.87         1.83	

The floating reference prices which Devon will pay the counterparties to the above gas price hedging instruments include several index prices based upon the area of the gas production that is hedged. For the hedged Canadian gas production, these reference prices are primarily based on index prices published by the Alberta Energy Company ("AECO"). For the hedged U.S. production, the reference prices are primarily based on index prices published by "Inside FERC" for the Rocky Mountains and San Juan Basin.
Devon has certain foreign currency hedging instruments that offset a portion of the exposure to currency fluctuations on Canadian oil sales that are based on U.S. dollar prices. Gains and losses recognized on these foreign currency hedging instruments are included as increases or decreases to realized oil sales. As of December 31, 1999, Devon had open foreign currency hedging instruments in which it will sell $30 million in 2000 at
81

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
average Canadian-to-U.S. dollar exchange rates of $0.7265. A portion of these hedging instruments can be extended an additional year at the option of the counterparty. If such options are exercised, Devon will sell an additional $10 million in 2001 at average Canadian-to-U.S. dollar exchange rates of $0.7102. Under these agreements, Devon will buy the same amount of dollars in each year at the floating exchange rate.
Devon's 1999, 1998 and 1997 consolidated balance sheets include deferred revenues of $0.4 million, $1.0 million and $3.8 million, respectively, for gains realized on the early termination of commodity and foreign currency hedging instruments in prior years. These deferred gains as of the end of 1999 will be recognized as oil and gas sales over periods ranging from ten months to one year as the hedged oil and gas production occurs.
12. RETIREMENT PLANS
Devon has non-contributory defined benefit retirement plans (the "Basic Plans") which include U.S. employees meeting certain age and service requirements. The benefits are based on the employee's years of service and compensation. Devon's funding policy is to contribute annually the maximum amount that can be deducted for federal income tax purposes. Rights to amend or terminate the Basic Plans are retained by Devon.
Devon also has separate defined benefit retirement plans (the "Supplementary Plans") which are non-contributory and include only certain employees whose benefits under the Basic Plans are limited by income tax regulations. The Supplementary Plans' benefits are based on the employee's years of service and compensation. Devon's funding policy for the Supplementary Plans is to fund the benefits as they become payable. Rights to amend or terminate the Supplementary Plans are retained by Devon.
Additionally, Devon assumed responsibility for the PennzEnergy sponsored defined benefit postretirement plans, which are unfunded, and cover substantially all of the former PennzEnergy employees who remained with Devon. Devon did not extend these benefits to other employees. The plans provide medical and life insurance benefits and are, depending on the type of plan, either contributory or non-contributory. The accounting for the health care plan anticipates future cost-sharing changes that are consistent with Devon's expressed intent to increase, where possible, contributions for future retirees. Furthermore, future contributions for both current and future salaried retirees have been limited to 200% of the 1992 retiree premium rates. Retirees will be required to absorb all future cost increases over that limit.
82

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The following table sets forth the plans' benefit obligations, plan assets, reconciliation of funded status, amounts recognized in the consolidated balance sheets and the actuarial assumptions used as of December 31:

                                                                                                  OTHER POSTRETIREMENT
                                                                     PENSION BENEFITS                 BENEFITS
                                                        ----------------------------------------  --------------------
                                                           1999           1998           1997           1999
                                                        ----------     ----------     ----------     ----------
                                                                                         (IN THOUSANDS)
Change in benefit obligation:
         Benefit obligation at beginning of year        $   15,141         11,659          8,029     $       --
     Service cost                                            2,537            985            706            138
     Interest cost                                           3,164            935            747            649
     Amendments                                                 --            293             --             --
     PennzEnergy merger                                     84,651             --             --         27,859
     Actuarial (loss) gain                                  (1,525)         1,773          1,463             --
         Benefits paid                                      (1,699)          (504)          (349)          (886)
         Establishment of new plan                              --             --          1,063             --
                                                        ----------     ----------     ----------     ----------
     Benefit obligation at end of year                     102,269         15,141         11,659         27,760
                                                        ----------     ----------     ----------     ----------

Change in plan assets:
     Fair value of plan assets at beginning of year          6,331          6,036          5,022             --
     Actual return on plan assets                            8,808            (87)           366             --
     PennzEnergy merger                                    104,181             --             --             --
     Employer contributions                                  1,173            886            997            886
     Benefits paid                                          (1,699)          (504)          (349)          (886)
                                                        ----------     ----------     ----------     ----------
     Fair value of plan assets at end of year              118,794          6,331          6,036             --
                                                        ----------     ----------     ----------     ----------

Funded status                                               16,525         (8,810)        (5,623)       (27,760)

Unrecognized net actuarial (gain) loss                      (2,223)         4,730          2,448             --
Unrecognized prior service cost                              1,566          1,822          1,973             --
                                                        ----------     ----------     ----------     ----------
Net amount recognized                                   $   15,868         (2,258)        (1,202)       (27,760)
                                                        ==========     ==========     ==========     ==========
The net amounts recognized in the consolidated
   balance sheets consist of:
     Prepaid (accrued) benefit cost                     $   15,868         (2,258)        (1,202)    $  (27,760)
     Additional minimum liability                           (3,110)        (2,987)        (2,557)            --
     Intangible asset                                        1,537          1,808          2,557             --
     Accumulated other comprehensive loss                    1,573          1,179             --             --
                                                        ----------     ----------     ----------     ----------
     Net amount recognized                              $   15,868         (2,258)        (1,202)    $  (27,760)
                                                        ==========     ==========     ==========     ==========

Assumptions:
     Discount rate                                            7.25%          6.50%          7.00%          7.25%
     Expected return on plan assets                           8.00%          8.50%          8.50%           N/A
     Rate of compensation increase                            5.00%          5.00%          5.00%           N/A	

83

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
The benefit obligation for the defined benefit pension plans with benefit obligations in excess of assets was $8.0 million as of December 31, 1999. No plan assets existed for these plans at December 31, 1999.
Net periodic benefit cost included the following components:

                                                                                              OTHER POSTRETIREMENT
                                                                   PENSION BENEFITS                BENEFITS
                                                         -----------------------------------  --------------------
                                                            1999         1998         1997         1999
                                                         ---------    ---------    ---------    ---------
                                                                                      (IN THOUSANDS)
Service cost                                             $   2,537          985          706    $     138
Interest cost                                                3,164          935          747          649
Expected return on plan assets                              (3,700)        (532)        (445)          --
Amortization of prior service cost                             256          256          194           --
Recognized net actuarial loss                                  320          111           59           --
                                                         ---------    ---------    ---------    ---------
Net periodic benefit cost                                $   2,577        1,755        1,261    $     787
                                                         =========    =========    =========    =========	

For measurement purposes, a 7% annual rate of increase in the per capita cost of covered health care benefits was assumed in 2000. The rate was assumed to decrease on a pro-rata basis annually to 5% in the year 2002 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one percentage-point change in assumed health care cost trend rates would have the following effects:

                                                                              ONE-PERCENTAGE         ONE-PERCENTAGE
                                                                              POINT INCREASE         POINT DECREASE
                                                                              --------------         --------------
                                                                                         (IN THOUSANDS)

Effect on total of service and interest cost components for 1999                 $  24                  $  (26)
Effect on year-end 1999 postretirement benefit obligation                          809                    (916)	

As a result of the PennzEnergy merger, Devon assumed certain postemployment benefits to former or inactive employees who are not retirees. These benefits include salary continuance, severance and disability health care and life insurance which are accounted for under SFAS No. 112, "Employer's Accounting for Postemployment Benefits." The accrued postemployment benefit liability was approximately $2.5 million at the end of 1999.
Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a certain percentage of the employees' contributions to the plan. The matching percentage is determined annually by the Board of Directors. Devon's matching contributions to the plan were $2.7 million, $1.0 million and $0.5 million for the years ended December 31, 1999, 1998 and 1997, respectively.
Devon has defined contribution plans for its Canadian employees. Devon contributes between 6% and 10% of the employee's base compensation, depending upon the employee's classification. Such contributions are subject to maximum amounts allowed under the Income Tax Act (Canada).
84

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes an amount equal to 2% of the base salary of each employee. The employees may elect to contribute up to 4% of their salary. If such employee contributions are made, they are matched by additional Devon contributions.
During the years 1999, 1998 and 1997, Devon's combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $1.9 million, $1.8 million and $1.2 million, respectively.
13. COMMITMENTS AND CONTINGENCIES
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon's estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon's financial position or results of operations after consideration of recorded accruals.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon's consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
Certain of Devon's subsidiaries acquired in the PennzEnergy merger are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of December 31, 1999, Devon's consolidated balance sheet included $6.7 million of accrued liabilities, reflected in "Other liabilities," for environmental remediation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is based in large part on (i) the availability of defenses to liability, including the availability of the "petroleum exclusion" under CERCLA and similar state laws, and/or (ii) Devon's current belief that its share of wastes at a particular site is or will be
85

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
viewed by the Environmental Protection Agency or other PRPs as being de minimis. As a result, Devon's monetary exposure is not expected to be material.
Ramco Dispute
In October 1995, subsidiaries of Devon acquired in the PennzEnergy merger filed an action, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, in the United States District Court for the Southern District of Texas, Houston Division, against Ramco Hazar Energy Limited, formerly known as Ramco Energy Limited (collectively "Ramco"). The underlying dispute involves Ramco's asserted claim to an interest in the Karabakh prospect, an oil and gas field located in the territorial waters of the Azerbaijan Republic in the Caspian Sea. Since the initiation of the litigation, the operator of the Karabakh prospect determined that the hydrocarbon accumulation tested by three exploratory wells was not commercial. The federal suit sought to compel Ramco to arbitrate certain disputes that have arisen between it and the Devon plaintiffs pursuant to the Federal Arbitration Act and the Convention on the Recognition and Enforcement of Foreign Arbitral Awards. After the filing of the federal action, the Devon plaintiffs filed an Original Petition for Declaration Relief in the 281st Judicial District Court of Harris County, Texas. The state suit, styled Pennzoil Exploration and Production Company, et al. v. Ramco Energy Limited and Ramco Hazar Energy Limited, which is expressly conditioned upon a determination in the federal suit that the disputes between the Devon plaintiffs and Ramco are not subject to arbitration, seeks a declaration that the Devon plaintiffs have not breached any agreements with Ramco, and do not owe and/or have not breached any fiduciary or other legal duty to Ramco including, without limitation, a duty of good faith and fair dealing. In November 1995, Ramco asserted a counterclaim in the state court action, asserting breach of contract and breach of fiduciary duties. The counterclaim seeks a declaratory judgment granting Ramco a participation interest in the Karabakh prospect, compensatory damages, exemplary damages, attorneys' fees, court costs and other unspecified relief.
The judge in the federal suit granted in part the plaintiffs' motion to compel arbitration and ordered arbitration to be held in New York, New York. The United States Court of Appeals for the Fifth Circuit generally affirmed the ruling of the judge in the federal suit and the Devon plaintiffs initiated arbitration. The parties have been engaged in settlement discussions and the selection of arbitrators has been suspended by agreement of the parties pending the outcome of the settlement discussions.
Royalty Matters
More than 30 oil companies, including Devon as a result of the PennzEnergy merger, are involved in disputes in which it is alleged that the oil companies and related parties have underpaid holders of royalty interests, overriding royalty interests and working interests in connection with the production of crude oil. The proceedings include suits in federal court in Texas, Louisiana, Mississippi and Wyoming (that have been consolidated into one proceeding in Texas) and in state court in Texas, Utah, Alabama and Louisiana. Certain parties to the federal litigation have entered into a global settlement agreement which provides for a conditional nationwide settlement, subject to opt-outs, of
86

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
the crude oil royalty, overriding royalty and working interest claims of all members of the settlement class, including claims in the federal litigation and in numerous other individual and class action cases pending throughout the United States. The federal court held a fairness hearing April 5, 1999, and the settlement was approved. The Amended Final Judgment was entered September 10, 1999. However, certain entities have appealed their objections to the settlement. Devon is a party to the settlement agreement, which explicitly refutes an admission of liability, but was entered into to avoid expensive and protracted litigation.
Also, pending is a separate suit in federal court in Texas alleging that more than 30 major oil companies, including Devon as a result of the PennzEnergy merger, underpaid royalties to the United States in connection with crude oil produced from United States owned and/or controlled lands since 1986. The claims were filed by private litigants under the federal False Claims Act, and after investigation, the United States served notice of its intent to intervene as to certain defendants. Devon has reached an agreement in principle with the United States and the private litigants to settle the claims made in the case. Devon believes that it has acted reasonably and paid royalties in good faith, but has entered into the settlement agreement, which explicitly refutes an admission of liability, to avoid expensive and protracted litigation. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such settlement of the royalty matters.
Maersk Rig Contracts
In December 1997, Pennzoil Venezuela Corporation, S.A. ("PVC"), a subsidiary of Devon as a result of the PennzEnergy merger, entered into a contract ("Contract #1") with Maersk Jupiter Drilling, S.A. ("Maersk") for the provision of a rig for drilling services relative to the anticipated drilling program associated with Devon's Block 68/79, Lake Maracaibo, Venezuela. The rig to be provided by Maersk was to be assembled and delivered to the Lake Maracaibo area and placed in service in October 1998. The term of Contract #1 was to October 1, 2001. A companion contract ("Contract #2") with Maersk for a second rig with a similar term for use in conjunction with the Block 70/80 drilling program was also executed by PVC's working interest partner in that Block.
With execution of Contract #1, construction of the rig destined for Block 68/79 proceeded until completion thereof. In October 1998, Maersk advised that it intended to commence mobilization of the rig to Lake Maracaibo. However, during the period of rig construction, changes had occurred in the scope and timing of the drilling program anticipated for Block 68/79, resulting in significant reduction of the need for drilling services originally envisioned in Contract #1. PVC instructed Maersk to cease mobilization and to stack the rig in Brownsville, Texas, where it currently remains.
The rig built for Contract #2 was delivered to Lake Maracaibo where it performed an abbreviated drilling program for both Blocks 68/79 and 70/80. It is currently stacked in Lake Maracaibo.
87

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
While both Contract #1 and #2 provide for early termination, the charge for such termination is established in each contract as the "Contract Standby Rate" which is currently estimated at $42,000 per day, per contract, with certain escalation factors for the balance of the term of each. Representatives of PVC and Maersk are engaged in negotiations relative to termination/settlement of both Contract #1 and Contract #2. As of December 31, 1999, Devon's consolidated balance sheet included accrued liabilities, reflected in "Other liabilities," for the expected cost to terminate/settle both Contract #1 and Contract #2. This liability was recorded at the time of the PennzEnergy merger. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the liability recognized for such termination/settlement of both Contract #1 and Contract #2.
Operating Leases
The following is a schedule by year of future minimum rental payments required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 1999:

YEAR ENDING DECEMBER 31,                                     (IN THOUSANDS)
------------------------
   2000                                                          $ 7,221
   2001                                                            4,285
   2002                                                            2,730
   2003                                                            2,462
   2004                                                            2,372
   Thereafter                                                      6,331
                                                                 -------
   Total minimum lease payments required                         $25,401
                                                                 =======	

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

                                                          (IN THOUSANDS)
1999                                                          $6,904
1998                                                          $3,119
1997                                                          $2,619	

14. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES
Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
88

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
As of September 30, 1998, the carrying value of Devon's domestic properties, less deferred income taxes, exceeded the full cost ceiling by $88 million. Accordingly, a $126.9 million pre-tax reduction of the carrying value of such properties was recorded in the third quarter of 1998. This reduction was partially offset by a related $38.9 million deferred income tax benefit, resulting in an after-tax charge of $88 million.
As of December 31, 1997, the carrying value of Northstar's Canadian oil and gas properties, less deferred income taxes, exceeded the full cost ceiling by $397.9 million. Accordingly, a $625.5 million pre-tax reduction of the carrying value of such properties was recorded in the fourth quarter of 1997. This reduction was partially offset by a related $227.6 million deferred income tax benefit, resulting in an after-tax charge of $397.9 million.
15. OIL AND GAS OPERATIONS
Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration, and development activities:

                                                                       TOTAL
                                                              YEAR ENDED DECEMBER 31,
                                                      ---------------------------------------
                                                         1999           1998          1997
                                                      -----------   -----------   -----------
                                                                  (IN THOUSANDS)
Property acquisition costs:
  Proved, excluding deferred income taxes             $ 1,966,669       135,167       510,331
  Deferred income taxes                                        --        21,382        94,822
                                                      -----------   -----------   -----------
  Total proved, including deferred income taxes       $ 1,966,669       156,549       605,153
                                                      ===========   ===========   ===========
  Unproved, excluding deferred income taxes:
    Business combinations                                  83,505         5,278        37,261
    Other acquisitions                                     22,383        37,027        13,075
  Deferred income taxes                                        --           661         6,082
                                                      -----------   -----------   -----------
  Total unproved, including deferred income taxes     $   105,888        42,966        56,418
                                                      ===========   ===========   ===========
Exploration costs                                     $    70,506        85,614        54,640
Development costs                                     $   124,226       152,105       162,244	

89

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                                    DOMESTIC
                                                                    ---------------------------------------
                                                                             YEAR ENDED DECEMBER 31,
                                                                    ---------------------------------------
                                                                        1999          1998          1997
                                                                    -----------   -----------   -----------
                                                                                (IN THOUSANDS)
Property acquisition costs:
  Proved, excluding deferred income taxes                           $ 1,635,637        27,349        10,891
                                                                                                -----------
  Deferred income taxes                                                      --            --         2,084
                                                                    -----------   -----------   -----------
  Total proved, including deferred income taxes                     $ 1,635,637        27,349        12,975
                                                                    ===========   ===========   ===========
  Unproved, excluding deferred income taxes:
    Business combinations                                                81,755            --            --
    Other acquisitions                                                   13,228        26,764         7,582
  Deferred income taxes                                                      --            --          (100)
                                                                    -----------   -----------   -----------
  Total unproved, including deferred income taxes                   $    94,983        26,764         7,482
                                                                    ===========   ===========   ===========
Exploration costs                                                   $    29,771        35,686        18,326
Development costs                                                   $    92,195        76,986        79,943	

                                                                                    CANADA
                                                                    ---------------------------------------
                                                                             YEAR ENDED DECEMBER 31,
                                                                    ---------------------------------------
                                                                       1999          1998           1997
                                                                    -----------   -----------   -----------
                                                                                  (IN THOUSANDS)
Property acquisition costs:
  Proved, excluding deferred income taxes                           $    29,532       107,818       499,440
  Deferred income taxes                                                      --        21,382        92,738
                                                                    -----------   -----------   -----------
  Total proved, including deferred income taxes                     $    29,532       129,200       592,178
                                                                    ===========   ===========   ===========
  Unproved, excluding deferred income taxes:
    Business combinations                                                    --         5,278        37,261
    Other acquisitions                                                    9,155        10,263         5,493
  Deferred income taxes                                                      --           661         6,182
                                                                    -----------   -----------   -----------
  Total unproved, including deferred income taxes                   $     9,155        16,202        48,936
                                                                    ===========   ===========   ===========
Exploration costs                                                   $    37,197        49,928        36,314
Development costs                                                   $    29,811        75,119        82,301	

                                                                               INTERNATIONAL
                                                                    ---------------------------------------
                                                                             YEAR ENDED DECEMBER 31,
                                                                    ---------------------------------------
                                                                        1999          1998          1997
                                                                    -----------   -----------   -----------
                                                                               (IN THOUSANDS)
Property acquisition costs:
  Proved, excluding deferred income taxes                           $   301,500            --            --
                                                                                                -----------
  Deferred income taxes                                                      --            --            --
                                                                    -----------   -----------   -----------
  Total proved, including deferred income taxes                     $   301,500            --            --
                                                                    ===========   ===========   ===========
  Unproved, excluding deferred income taxes:
    Business combinations                                                 1,750            --            --
    Other acquisitions                                                       --            --            --
  Deferred income taxes                                                      --            --            --
                                                                    -----------   -----------   -----------
  Total unproved, including deferred income taxes                   $     1,750            --            --
                                                                    ===========   ===========   ===========
Exploration costs                                                   $     3,538            --            --
Development costs                                                   $     2,220            --            --	

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses which are related to property acquisition, exploration and development
90

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
activities. Such capitalized expenses, which are included in the costs shown in the preceding tables, were $18.7 million, $9.6 million and $7.5 million in the years 1999, 1998 and 1997, respectively.
Due to the tax-free nature of the PennzEnergy merger, additional deferred tax liabilities of $338.9 million were recorded in 1999 and allocated to goodwill.
During 1997, various uncertainties that existed at year-end 1996 regarding the tax basis and liabilities assumed in the acquisition of Kerr-McGee Corporation's North American onshore oil and gas exploration and production business and properties ("KMG-NAOS") were resolved. This resulted in an additional $5.5 million being allocated in 1997 to the proved properties acquired in the 1996 KMG-NAOS transaction. Of this amount, $3.1 million was for liabilities assumed and $2.4 million was for additional deferred tax liabilities created. This additional $5.5 million is included in the preceding table of costs incurred in 1997. The resolution of the uncertainties also resulted in a reduction of $0.1 million in 1997 to the deferred tax liabilities originally allocated in 1996 to the KMG-NAOS unproved properties.
Due to the tax-free nature of the Morrison Transaction, additional deferred tax liabilities of $128.5 million were recorded in 1997. Of this amount, $92.7 million was allocated to proved oil and gas properties and $6.2 million was allocated to unproved properties. The remaining amount of $29.6 million was allocated to non-oil and gas properties.
Results of Operations for Oil and Gas Producing Activities
The following tables include revenues and expenses associated directly with Devon's oil and gas producing activities. They do not include any allocation of Devon's interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net earnings of Devon's oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil and gas sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent differences.
91

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                               TOTAL
                                                               --------------------------------------
                                                                       YEAR ENDED DECEMBER 31,
                                                               --------------------------------------
                                                                  1999          1998          1997
                                                               ----------    ----------    ----------
                                                         (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales                         $  715,503       369,660       452,104
Production and operating expenses                                (189,903)     (127,400)     (120,124)
Depreciation, depletion and amortization                         (244,517)     (119,719)     (164,977)
Amortization of goodwill                                          (16,111)           --            --
Reduction of carrying value of oil and gas properties                  --      (126,900)     (625,514)
Income tax (expense) benefit                                     (112,684)      (19,385)      159,511
                                                               ----------    ----------    ----------
Results of operations for oil and gas producing
   activities                                                  $  152,288       (23,744)     (299,000)
                                                               ==========    ==========    ==========
Depreciation, depletion and amortization per equivalent
        barrel of production                                   $     4.65          3.32          4.86
                                                               ==========    ==========    ==========	

                                                                             DOMESTIC
                                                               --------------------------------------
                                                                       YEAR ENDED DECEMBER 31,
                                                               --------------------------------------
                                                                  1999          1998          1997
                                                               ----------    ----------    ----------
                                                         (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales                         $  519,502       208,630       273,860
Production and operating expenses                                (137,209)      (77,829)      (75,758)
Depreciation, depletion and amortization                         (179,941)      (76,327)      (73,091)
Amortization of goodwill                                          (16,106)           --            --
Reduction of carrying value of oil and gas properties                  --      (126,900)           --
Income tax (expense) benefit                                      (74,614)       18,230       (44,648)
                                                               ----------    ----------    ----------
Results of operations for oil and gas producing
   activities                                                  $  111,632       (54,196)       80,363
                                                               ==========    ==========    ==========
Depreciation, depletion and amortization per equivalent
        barrel of production                                   $     5.30          4.24          4.13
                                                               ==========    ==========    ==========	

92

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                              CANADA
                                                                ------------------------------------
                                                                       YEAR ENDED DECEMBER 31,
                                                                ------------------------------------
                                                                   1999         1998         1997
                                                                ----------   ----------   ----------
                                                          (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales                          $  193,100      161,030      178,244
Production and operating expenses                                  (51,194)     (49,571)     (44,366)
Depreciation, depletion and amortization                           (64,514)     (43,392)     (91,886)
Reduction of carrying value of oil and gas properties                   --           --     (625,514)
Income tax (expense) benefit                                       (37,736)     (37,615)     204,159
                                                                ----------   ----------   ----------
Results of operations for oil and gas producing
   activities                                                   $   39,656       30,452     (379,363)
                                                                ==========   ==========   ==========
Depreciation, depletion and amortization per equivalent
        barrel of production                                    $     3.56         2.41         5.64
                                                                ==========   ==========   ==========	

                                                                           INTERNATIONAL
                                                                ------------------------------------
                                                                       YEAR ENDED DECEMBER 31,
                                                                ------------------------------------
                                                                   1999         1998         1997
                                                                ----------   ----------   ----------
                                                          (IN THOUSANDS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)
Oil, gas and natural gas liquids sales                          $    2,901           --           --
Production and operating expenses                                   (1,500)          --           --
Depreciation, depletion and amortization                               (62)          --           --
Amortization of goodwill                                                (5)          --           --
Income tax expense                                                    (334)          --           --
                                                                ----------   ----------   ----------
Results of operations for oil and gas producing activities      $    1,000           --           --
                                                                ==========   ==========   ==========
Depreciation, depletion and amortization per equivalent
        barrel of production                                    $     0.14           --           --
                                                                ==========   ==========   ==========	

16. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)
The following supplemental unaudited information regarding the oil and gas activities of Devon is presented pursuant to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, "Disclosures About Oil and Gas Producing Activities."
Quantities of Oil and Gas Reserves
Set forth below is a summary of the changes in the net quantities of crude oil, natural gas and natural gas liquids reserves for each of the three years ended December 31, 1999. Approximately 97%, 93% and 93%, of the respective year-end 1999, 1998 and 1997 domestic proved reserves were calculated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd. and, for 1999 only, Ryder-Scott Company Petroleum Consultants. The remaining percentages of domestic reserves are based on Devon's own estimates. All of the year-end 1999 Canadian proved reserves were calculated by the independent petroleum consultants Paddock Lindstrom & Associates. All of the
93

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
year-end 1998 and 1997 Canadian proved reserves were calculated by the independent petroleum consultants of Paddock Lindstrom & Associates, AMH Group Ltd. and, for 1997 only, John P. Hunter & Associates, Ltd. All of the international proved reserves other than Canada as of December 31, 1999, were calculated by the independent petroleum consultants of Ryder-Scott Company Petroleum Consultants.

                                                                    TOTAL
                                                 -------------------------------------------
                                                                                   NATURAL
                                                                                     GAS
                                                     OIL             GAS           LIQUIDS
                                                   (MBBLS)          (MMCF)         (MBBLS)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1996               80,155         898,319          14,190
        Revisions of estimates                            42         (46,390)          1,544
        Extensions and discoveries                     9,387         145,508             424
        Purchase of reserves                          19,396         275,592           2,914
        Production                                   (11,783)       (121,810)         (1,891)
        Sale of reserves                                (156)           (615)             (3)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1997               97,041       1,150,604          17,178
        Revisions of estimates                        (6,277)        (68,895)            176
        Extensions and discoveries                     1,897         116,227             452
        Purchase of reserves                           8,683         145,629             518
        Production                                   (11,903)       (133,065)         (1,939)
        Sale of reserves                              (5,984)        (11,606)           (306)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1998               83,457       1,198,894          16,079
        Revisions of estimates                         3,427          (8,958)          3,065
        Extensions and discoveries                     1,309         136,957           2,042
        Purchase of reserves                         235,512         821,547          32,795
        Production                                   (15,416)       (198,457)         (4,022)
        Sale of reserves                              (4,372)        (53,456)           (142)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1999              303,917       1,896,527          49,817
                                                 ===========     ===========     ===========
Proved developed reserves as of:
        December 31, 1996                             72,330         810,465          12,563
        December 31, 1997                             88,258         984,374          16,332
        December 31, 1998                             73,846       1,052,647          15,081
        December 31, 1999                            171,249       1,751,385          47,502	

94

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                  DOMESTIC
                                                 -------------------------------------------
                                                                                   NATURAL
                                                                                     GAS
                                                    OIL              GAS           LIQUIDS
                                                   (MBBLS)          (MMCF)         (MBBLS)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1996               59,951         554,661          11,695
        Revisions of estimates                        (1,358)        (21,124)          1,531
        Extensions and discoveries                     7,394          94,925             301
        Purchase of reserves                           1,126             992              16
        Production                                    (6,055)        (61,015)         (1,468)
        Sale of reserves                                (156)           (615)             (3)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1997               60,902         567,824          12,072
        Revisions of estimates                       (12,560)          1,507             424
        Extensions and discoveries                     1,242          53,708             371
        Purchase of reserves                             513          39,855              --
        Production                                    (5,646)        (65,907)         (1,373)
        Sale of reserves                                  --              --              --
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1998               44,451         596,987          11,494
        Revisions of estimates                         6,255          32,086           3,333
        Extensions and discoveries                     1,090          84,259           1,594
        Purchase of reserves                         106,008         803,434          32,709
        Production                                    (9,791)       (124,896)         (3,322)
        Sale of reserves                              (2,489)         (7,784)             (4)
                                                 -----------     -----------     -----------
Proved reserves as of December 31, 1999              145,524       1,384,086          45,804
                                                 ===========     ===========     ===========
Proved developed reserves as of:
        December 31, 1996                             52,672         529,407          10,328
        December 31, 1997                             53,059         462,082          11,289
        December 31, 1998                             40,631         469,064          10,577
        December 31, 1999                            128,167       1,246,131          43,637	

95

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                           CANADA
                                                          ----------------------------------------
                                                                                          NATURAL
                                                                                            GAS
                                                              OIL           GAS           LIQUIDS
                                                            (MBBLS)        (MMCF)         (MBBLS)
                                                          ----------     ----------     ----------
Proved reserves as of December 31, 1996                       20,204        343,658          2,495
        Revisions of estimates                                 1,400        (25,266)            13
        Extensions and discoveries                             1,993         50,583            123
        Purchase of reserves                                  18,270        274,600          2,898
        Production                                            (5,728)       (60,795)          (423)
        Sale of reserves                                          --             --             --
                                                          ----------     ----------     ----------
Proved reserves as of December 31, 1997                       36,139        582,780          5,106
        Revisions of estimates                                 6,283        (70,402)          (248)
        Extensions and discoveries                               655         62,519             81
        Purchase of reserves                                   8,170        105,774            518
        Production                                            (6,257)       (67,158)          (566)
        Sale of reserves                                      (5,984)       (11,606)          (306)
                                                          ----------     ----------     ----------
Proved reserves as of December 31, 1998                       39,006        601,907          4,585
        Revisions of estimates                                (2,828)       (41,044)          (268)
        Extensions and discoveries                               219         52,698            448
Purchase of reserves                                           2,796         11,890             86
        Production                                            (5,178)       (73,561)          (700)
        Sale of reserves                                      (1,883)       (45,672)          (138)
                                                          ----------     ----------     ----------
Proved reserves as of December 31, 1999                       32,132        506,218          4,013
                                                          ==========     ==========     ==========
Proved developed reserves as of
        December 31, 1996                                     19,658        281,058          2,235
        December 31, 1997                                     35,199        522,292          5,043
        December 31, 1998                                     33,215        583,583          4,504
        December 31, 1999                                     29,268        501,376          3,865	

96

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                  INTERNATIONAL
                                                 ----------------------------------------------
                                                                                     NATURAL
                                                                                       GAS
                                                      OIL             GAS            LIQUIDS
                                                    (MBBLS)          (MMCF)          (MBBLS)
                                                 ------------     ------------     ------------
Proved reserves as of December 31, 1998                    --               --               --
        Revisions of estimates                             --               --               --
        Extensions and discoveries                         --               --               --
        Purchase of reserves                          126,708            6,223               --
        Production                                       (447)              --               --
        Sale of reserves                                   --               --               --
                                                 ------------     ------------     ------------
Proved reserves as of December 31, 1999               126,261            6,223               --
                                                 ============     ============     ============
Proved developed reserves as of
        December 31, 1999                              13,814            3,878               --	

Standardized Measure of Discounted Future Net Cash Flows
The accompanying tables reflect the standardized measure of discounted future net cash flows relating to Devon's interest in proved reserves:

                                                              TOTAL
                                         ----------------------------------------------
                                                          DECEMBER 31,
                                         ----------------------------------------------
                                             1999              1998             1997
                                         ------------     ------------     ------------
                                                          (IN THOUSANDS)
Future cash inflows                      $ 11,308,329        2,984,585        3,728,815
Future costs:
   Development                               (786,878)        (157,577)        (158,761)
   Production                              (3,808,693)      (1,169,988)      (1,348,459)
Future income tax expense                    (916,198)        (125,975)        (399,972)
                                         ------------     ------------     ------------
Future net cash flows                       5,796,560        1,531,045        1,821,623
10% discount to reflect timing of
   cash flows                              (2,657,626)        (599,457)        (720,947)
                                         ------------     ------------     ------------
Standardized measure of
   discounted future net cash flows      $  3,138,934          931,588        1,100,676
                                         ============     ============     ============	

97

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                     DOMESTIC
                                                    -------------------------------------------
                                                                    DECEMBER 31,
                                                    -------------------------------------------
                                                       1999            1998            1997
                                                    -----------     -----------     -----------
                  `                                               (IN THOUSANDS)
Future cash inflows                                 $ 6,971,518       1,650,930       2,304,602
Future costs:
   Development                                         (427,097)        (72,215)        (83,350)
   Production                                        (2,449,871)       (678,732)       (806,130)
Future income tax expense                              (495,599)        (86,412)       (269,880)
                                                    -----------     -----------     -----------
Future net cash flows                                 3,598,951         813,571       1,145,242
10% discount to reflect timing of
   cash flows                                        (1,398,612)       (319,889)       (481,263)
                                                    -----------     -----------     -----------
Standardized measure of
   discounted future net cash flows                 $ 2,200,339         493,682         663,979
                                                    ===========     ===========     ===========	

                                                                     CANADA
                                                    -------------------------------------------
                                                                   DECEMBER 31,
                                                    -------------------------------------------
                                                       1999             1998            1997
                                                    -----------     -----------     -----------
                                                                  (IN THOUSANDS)
Future cash inflows                                 $ 1,666,358       1,333,655       1,424,213
Future costs:
   Development                                          (66,631)        (85,362)        (75,411)
   Production                                          (514,825)       (491,256)       (542,329)
Future income tax expense                              (204,290)        (39,563)       (130,092)
                                                    -----------     -----------     -----------
Future net cash flows                                   880,612         717,474         676,381
10% discount to reflect timing of
   cash flows                                          (320,722)       (279,568)       (239,684)
                                                    -----------     -----------     -----------
Standardized measure of
   discounted future net cash flows                 $   559,890         437,906         436,697
                                                    ===========     ===========     ===========	

98

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                        INTERNATIONAL
                                         ------------------------------------------
                                                         DECEMBER 31,
                                         ------------------------------------------
                                            1999             1998          1997
                                         -----------     -----------    -----------
                                                       (IN THOUSANDS)
Future cash inflows                      $ 2,670,453              --             --
Future costs:
   Development                              (293,150)             --             --
   Production                               (843,997)             --             --
Future income tax expense                   (216,309)             --             --
                                         -----------     -----------    -----------
Future net cash flows                      1,316,997              --             --
10% discount to reflect timing of
   cash flows                               (938,292)             --             --
                                         -----------     -----------    -----------
Standardized measure of
   discounted future net cash flows      $   378,705              --             --
                                         ===========     ===========    ===========	

Future cash inflows are computed by applying year-end prices (averaging $21.96 per barrel of oil, adjusted for transportation and other charges, $1.87 per Mcf of gas and $15.74 per barrel of natural gas liquids at December 31, 1999) to the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements in existence at year-end.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect to permanent differences and tax credits, but do not reflect the impact of future operations.
99

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows
Principal changes in the standardized measure of discounted future net cash flows attributable to Devon's proved reserves are as follows:

                                                       YEAR ENDED DECEMBER 31,
                                            -------------------------------------------
                                               1999            1998             1997
                                            -----------     -----------     -----------
                                                           (IN THOUSANDS)
Beginning balance                           $   931,588       1,100,676       1,454,974
Sales of oil, gas and natural gas
   liquids, net of production costs            (525,600)       (242,260)       (331,980)
Net changes in prices and
   production costs                             658,640        (304,593)       (890,534)
Extensions, discoveries, and improved
   recovery, net of future
   development costs                            115,132          64,614          75,698
Purchase of reserves, net of future
   development costs                          2,147,781         113,655         246,173
Development costs incurred during
   the period which reduced future
   development costs                             37,080          45,699          62,868
Revisions of quantity estimates                  42,479         (58,314)        (12,251)
Sales of reserves in place                      (74,207)        (28,365)         (1,395)
Accretion of discount                           100,904         134,065         198,401
Net change in income taxes                     (417,637)        162,517         300,684
Other, primarily changes in timing              122,774         (56,106)         (1,962)
                                            -----------     -----------     -----------
Ending balance                              $ 3,138,934         931,588       1,100,676
                                            ===========     ===========     ===========	

17. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has three segments: its operations in the U.S., its operations in Canada, and its international operations outside of North America. Substantially all of these segments' operations involve oil and gas producing activities. Certain information regarding such activities for each segment is included in Notes 15 and 16.
Following is certain financial information regarding Devon's segments for 1999, 1998 and 1997. The revenues reported are all from external customers.
100

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997

                                                                         U.S.         CANADA       INTERNATIONAL      TOTAL
                                                                     -----------    -----------    -------------    -----------
                                                                                            (IN THOUSANDS)
AS OF DECEMBER 31, 1999:
Current assets                                                       $   321,528         69,279          26,387         417,194
Property and equipment, net of accumulated depreciation,
  depletion and amortization                                           2,373,815        467,465         314,640       3,155,920
Other assets                                                             915,558             98         134,390       1,050,046
                                                                     -----------    -----------     -----------     -----------
          Total assets                                               $ 3,610,901        536,842         475,417       4,623,160
                                                                     ===========    ===========     ===========     ===========

Current liabilities                                                      166,144         44,989          16,311
                                                                                                                        227,444
Long-term debt                                                         1,447,780        339,341              --       1,787,121
Deferred tax liabilities                                                 362,414          1,733          26,718         390,865
Other liabilities                                                        146,706          3,098          42,406         192,210
Stockholders' equity                                                   1,487,857        147,681         389,982       2,025,520
                                                                     -----------    -----------     -----------     -----------
          Total liabilities and stockholders' equity                 $ 3,610,901        536,842         475,417       4,623,160
                                                                     ===========    ===========     ===========     ===========

YEAR ENDED DECEMBER 31, 1999:
REVENUES
   Oil sales                                                         $   194,162         76,171           2,901         273,234
   Gas sales                                                             279,030        106,895              --         385,925
   Natural gas liquids sales                                              46,310         10,034              --
                                                                                                                         56,344
   Other                                                                  14,074          4,652             270          18,996
                                                                     -----------    -----------     -----------     -----------
          Total revenues                                                 533,576        197,752           3,171         734,499
                                                                     -----------    -----------     -----------     -----------

COSTS AND EXPENSES
   Lease operating expenses                                              115,517         49,831           1,500
                                                                                                                        166,848
   Production taxes                                                       21,692          1,363              --          23,055
   Depreciation, depletion and amortization of property
       and equipment                                                     188,892         65,176             207         254,275
   Amortization of goodwill                                               16,106             --               5
                                                                                                                         16,111
   General and administrative expenses                                    39,107         12,189           2,549          53,845
   Interest expense                                                       41,979         24,945             (11)
                                                                                                                         66,913
   Deferred effect of changes in foreign currency exchange
     rate on subsidiary's long-term debt                                      --        (13,154)             --         (13,154)
   Distributions on preferred securities of subsidiary trust               6,884             --              --           6,884
                                                                                    -----------     -----------     -----------
          Total costs and expenses                                       430,177        140,350           4,250         574,777
                                                                     -----------    -----------     -----------     -----------

Earnings (loss) before income tax expense (benefit)                      103,399         57,402          (1,079)        159,722

INCOME TAX EXPENSE (BENEFIT)
   Current                                                                21,748          2,908              --
                                                                                                                         24,656
   Deferred                                                               14,019         26,654            (163)         40,510
                                                                     -----------    -----------     -----------     -----------
          Total income tax expense (benefit)                              35,767         29,562            (163)         65,166
                                                                     -----------    -----------     -----------     -----------

Net earnings (loss)                                                  $    67,632         27,840            (916)         94,556
                                                                     ===========    ===========     ===========     ===========

Capital expenditures                                                 $   213,754         91,853           9,198         314,805
                                                                     ===========    ===========     ===========     ===========	

101

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)

                                                                      U.S.          CANADA      INTERNATIONAL       TOTAL
                                                                  -----------     -----------   -------------    -----------
                                                                                          (IN THOUSANDS)
AS OF DECEMBER 31, 1998:
Current assets                                                    $    57,098          53,550              --        110,648
Property and equipment, net of accumulated depreciation,
  depletion and amortization                                          635,440         465,488              --      1,100,928
Other assets                                                           13,326           1,454              --         14,780
                                                                  -----------     -----------     -----------    -----------
          Total assets                                            $   705,864         520,492              --      1,226,356
                                                                  ===========     ===========     ===========    ===========

Current liabilities                                                    25,032          55,624                             --
                                                                                                                      80,656
Long-term debt                                                         35,000         370,271              --        405,271
Deferred tax liabilities (assets)                                      57,393         (24,174)             --         33,219
Other liabilities                                                      28,987           5,760              --         34,747
TCP Securities                                                        149,500              --              --        149,500
Stockholders' equity                                                  409,952         113,011              --        522,963
                                                                  -----------     -----------     -----------    -----------
          Total liabilities and stockholders' equity              $   705,864         520,492              --      1,226,356
                                                                  ===========     ===========     ===========    ===========

YEAR ENDED DECEMBER 31, 1998:
REVENUES
   Oil sales                                                      $    70,286          73,338              --        143,624
   Gas sales                                                          126,273          83,071              --        209,344
   Natural gas liquids sales                                           12,071           4,621                             --
                                                                                                                      16,692
   Other                                                                4,094          13,754              --         17,848
                                                                  -----------     -----------     -----------    -----------
          Total revenues                                              212,724         174,784              --        387,508
                                                                  -----------     -----------     -----------    -----------

COSTS AND EXPENSES
   Lease operating expenses                                            65,574          47,910                             --
                                                                                                                     113,484
   Production taxes                                                    12,255           1,661              --         13,916
   Depreciation, depletion and amortization                            79,254          44,590              --        123,844
   General and administrative expenses                                 11,052          12,502              --         23,554
   Northstar Combination expenses                                       3,064          10,085              --         13,149
   Interest expense                                                       658          21,974                             --
                                                                                                                      22,632
   Deferred effect of changes in foreign currency exchange
     rate on subsidiary's long-term debt                                   --          16,104              --         16,104
   Distributions on preferred securities of subsidiary trust            9,717              --              --          9,717
   Reduction of carrying value of oil and gas properties              126,900              --              --        126,900
                                                                  -----------     -----------     -----------    -----------
          Total costs and expenses                                    308,474         154,826              --        463,300
                                                                  -----------     -----------     -----------    -----------

Earnings (loss) before income tax expense (benefit)                   (95,750)         19,958              --        (75,792)

INCOME TAX EXPENSE (BENEFIT)
   Current                                                              5,712           1,975                             --
                                                                                                                       7,687
   Deferred                                                           (34,360)         11,166              --        (23,194)
                                                                  -----------     -----------     -----------    -----------
          Total income tax expense (benefit)                          (28,648)         13,141              --        (15,507)
                                                                  -----------     -----------     -----------    -----------

Net earnings (loss)                                               $   (67,102)          6,817              --        (60,285)
                                                                  ===========     ===========     ===========    ===========

Capital expenditures                                              $   170,334         205,178              --        375,512
                                                                  ===========     ===========     ===========    ===========	

102

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
17. SEGMENT INFORMATION (CONTINUED)

                                                                         U.S.         CANADA       INTERNATIONAL      TOTAL
                                                                     -----------    -----------    -------------   -----------
                                                                                           (IN THOUSANDS)
AS OF DECEMBER 31, 1997:
Current assets                                                       $    81,517        131,740              --        213,257
Property and equipment, net of accumulated depreciation,
  depletion and amortization                                             679,677        315,606              --        995,283
Other assets                                                              14,940         25,506              --         40,446
                                                                     -----------    -----------     -----------    -----------
          Total assets                                               $   776,134        472,852              --      1,248,986
                                                                     ===========    ===========     ===========    ===========

Current liabilities                                                       29,016        107,298                             --
                                                                                                                       136,314
Long-term debt                                                                --        305,337              --        305,337
Deferred tax liabilities (assets)                                         92,042        (60,217)             --         31,825
Other liabilities                                                         21,040          8,424              --         29,464
TCP Securities                                                           149,500             --              --        149,500
Stockholders' equity                                                     484,536        112,010              --        596,546
                                                                     -----------    -----------     -----------    -----------
          Total liabilities and stockholders' equity                 $   776,134        472,852              --      1,248,986
                                                                     ===========    ===========     ===========    ===========

YEAR ENDED DECEMBER 31, 1997:
REVENUES
   Oil sales                                                         $   115,504         92,221              --        207,725
   Gas sales                                                             139,018         80,441              --        219,459
   Natural gas liquids sales                                              19,338          5,582                             --
                                                                                                                        24,920
   Other                                                                   4,974         42,581              --         47,555
                                                                     -----------    -----------     -----------    -----------
          Total revenues                                                 278,834        220,825              --        499,659
                                                                     -----------    -----------     -----------    -----------

COSTS AND EXPENSES
   Lease operating expenses                                               58,112         42,785                             --
                                                                                                                       100,897
   Production taxes                                                       17,646          1,581              --         19,227
   Depreciation, depletion and amortization                               75,944         93,164              --        169,108
   General and administrative expenses                                    10,481         13,900              --         24,381
   Interest expense                                                          269         18,519                             --
                                                                                                                        18,788
   Deferred effect of changes in foreign currency exchange
     rate on subsidiary's long-term debt                                      --          5,860              --          5,860
   Distributions on preferred securities of subsidiary trust               9,717             --              --          9,717
   Reduction of carrying value of oil and gas properties                      --        625,514              --        625,514
                                                                     -----------    -----------     -----------    -----------
          Total costs and expenses                                       172,169        801,323              --        973,492
                                                                     -----------    -----------     -----------    -----------

Earnings (loss) before income tax expense (benefit)                      106,665       (580,498)             --       (473,833)

INCOME TAX EXPENSE (BENEFIT)
   Current                                                                21,180          5,677                             --
                                                                                                                        26,857
   Deferred                                                               18,603       (219,302)             --       (200,699)
                                                                     -----------    -----------     -----------    -----------
          Total income tax expense (benefit)                              39,783       (213,625)             --       (173,842)
                                                                     -----------    -----------     -----------    -----------

Net earnings (loss)                                                  $    66,882       (366,873)             --       (299,991)
                                                                     ===========    ===========     ===========    ===========

Capital expenditures                                                 $   120,689        167,302              --        287,991
                                                                     ===========    ===========     ===========    ===========	

103

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Following is a summary of the unaudited interim results of operations for the years ended December 31, 1999 and 1998.

                                                                           1999
                                            -----------------------------------------------------------------
                                              FIRST         SECOND        THIRD         FOURTH          FULL
                                             QUARTER        QUARTER      QUARTER        QUARTER         YEAR
                                            --------        -------      --------       -------        ------
                                                         (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Oil, gas and natural gas liquids
   sales                                     $85,393        102,093       214,241       313,776       715,503
Total revenues                               $87,266        104,312       219,851       323,070       734,499
Net earnings                                 $ 5,980         16,209        24,452        47,915        94,556

Net earnings per common share:
   Basic                                     $   0.12          0.33          0.39          0.55          1.51
   Diluted                                   $   0.12          0.33          0.38          0.52          1.46	

                                                                           1998
                                            -----------------------------------------------------------------
                                             FIRST          SECOND        THIRD          FOURTH        FULL
                                            QUARTER         QUARTER      QUARTER        QUARTER        YEAR
                                            --------        -------      --------       -------        ------
                                                         (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Oil, gas and natural gas liquids
   sales                                    $  98,308         93,507        90,469        87,376       369,660
Total revenues                              $ 100,437        104,775        92,870        89,426       387,508
Net earnings (loss)                         $  14,225         12,173       (83,195)       (3,488)      (60,285)
Net earnings (loss) per common share:
   Basic                                    $    0.29           0.25         (1.72)        (0.07)        (1.25)
   Diluted                                  $    0.29           0.25         (1.72)        (0.07)        (1.25)	

The third quarter of 1998 includes a $126.9 million pre-tax reduction of the carrying value of U.S. oil and gas properties. The after-tax effect of this charge was $88 million, or $1.82 per share. The fourth quarter of 1998 includes $13.1 million of costs incurred in connection with the Northstar Combination. The after-tax effect of these expenses was $9.7 million, or $0.20 per share.
104

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy Statement to be filed by the Company pursuant to Regulation 14A of the General Rules and Regulations under the Securities and Exchange Act of 1934 not later than April 29, 2000.
105

PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement Schedules appearing at Item 8 on Page 48 of this report.
2. Consolidated Financial Statement Schedules
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated financial statements or notes thereto.
3. Exhibits
2.1 Amended and Restated Agreement and Plan of Merger among Registrant, Devon Energy Corporation (Oklahoma) (formerly Devon Energy Corporation, an Oklahoma corporation), Devon Oklahoma Corporation and PennzEnergy Company dated as of May 19, 1999 (incorporated by reference to Exhibit 2.1 to Registrant's Form S-4, File No. 333-82903).
2.2 Amended and Restated Combination Agreement between the Registrant and Northstar Energy Corporation dated as of June 29, 1998 (incorporated by reference to Annex B to Registrant's definitive proxy statement for a special meeting of shareholders, filed November 6, 1998).
3.1 Registrant's Restated Certificate of Incorporation (incorporated by reference to Exhibit 3 to Registrant's Form 8-K filed on August 18, 1999).
3.2 Registrant's Bylaws (incorporated by reference to Exhibit 3.3 to Registrant's Registration Statement on Form S-4, File No. 333-82903 as filed on July 15, 1999).
4.1 Form of Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Registrant's Form 8-K filed on August 18, 1999).
106

4.2 Rights Agreement dated as of August 17, 1999 between Registrant and BankBoston, N.A. (incorporated by reference to Exhibit 4.2 to Registrant's Form 8-K filed on August 18, 1999).
4.3 Certificate of Designations of Series A Junior Participating Preferred Stock of Registrant (incorporated by reference to Exhibit 4.3 to Registrant's Form 8-K filed on August 18, 1999).
4.4 Certificate of Designations of the 6.49% Cumulative Preferred Stock, Series A of Registrant (incorporated by reference to Exhibit 4.4 to Registrant's Form 8-K filed on August 18, 1999).
4.5 Description of Capital Stock of Registrant (incorporated by reference to Exhibit 4.9 to Registrant's Form 8-K filed on August 18, 1999).
4.6 Indenture dated as of December 15, 1992 between Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Texas Commerce Bank National Association, Trustee (incorporated by reference to Exhibit 4(o) to Pennzoil Company's Form 10-K filed on March 10, 1993 (SEC File No. 1-5591)).
4.7 Third Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.90% Exchangeable Senior Debentures due August 15, 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company's 1998 Form 10-K filed on March 23, 1999).
4.8 Fourth Supplemental Indenture dated as of August 3, 1998 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association, setting forth the terms of the 4.95% Exchangeable Senior Debentures due August 15, 2008 (incorporated by reference to Exhibit 4(g) to PennzEnergy Company's 1998 Form 10-K filed on March 23, 1999).
107

4.9 Fifth Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of December 15, 1992 among Registrant (as successor by merger to PennzEnergy, as successor to Pennzoil Company) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4.7 to Registrant's Form 8-K filed on August 18, 1999).
4.10 Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4(a) to Pennzoil Company's Form 10-Q filed on July 31, 1986 (SEC File No. 1-5591).
4.11 First Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of February 15, 1986 among Registrant (as successor by merger to PennzEnergy) and Chase Bank of Texas, National Association (incorporated by reference to Exhibit 4.8 to Registrant's Form 8-K filed on August 18, 1999).
4.12 Second Supplemental Indenture dated as of August 17, 1999 to Indenture dated as of July 3, 1996 among the Registrant and The Bank of New York, as Trustee and the First Supplemental Indenture dated as of July 3, 1996 between the Registrant and The Bank of New York, as Trustee, relating to the issuance of 6.5% Trust Convertible Preferred Junior Subordinated Debentures (incorporated by reference to Exhibit 4.6 to Registrant's Form 8-K filed on August 18, 1999).
4.13 Amending Support Agreement dated as of August 17, 1999 between Registrant and Northstar Energy Corporation (incorporated by reference to Exhibit 4.5 to Registrant's Form 8-K filed on August 18, 1999).
4.14 Support Agreement, dated December 10, 1998, between the Registrant and Northstar Energy Corporation (incorporated by reference to Exhibit 4.1 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K dated as of December 11, 1998).
4.15 Registration Rights Agreement, dated December 31, 1996, by and between Registrant and Kerr-McGee Corporation
108

(incorporated by reference to Exhibit 4.4 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on January 14, 1997).
4.16 Exchangeable Share Provisions (incorporated by reference to Exhibit 4.2 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on December 23, 1998).
4.17 Amended Exchangeable Share Provisions dated as of August 17, 1999.
9.1 Voting and Exchange Trust Agreement, dated December 10, 1998, by and between the Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company (incorporated by reference to Exhibit 9 to Devon Energy Corporation (Oklahoma)'s (predecessor of Registrant) Form 8-K filed on December 23, 1998).
9.2 Amending Voting and Exchange Trust Agreement, dated as of August 17, 1999, by and between Registrant, Northstar Energy Corporation and CIBC Mellon Trust Company (incorporated by reference to Exhibit 9 to Registrant's Form 8-K filed on August 18, 1999).
10.1 U.S. Credit Agreement, dated October 15, 1999 among the Registrant, as U.S. Borrower, Bank of America, N.A., as Administrative Agent, Bank of America Securities, LLC, as Lead Arranger, Bank One, Texas, N.A., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union National Bank, as Co-Documentation Agent, and Certain Financial Institutions, as Lenders (incorporated by reference to Exhibit 10.1 to Registrant's Form 10-Q filed on November 8, 1999).
10.2 Canadian Credit Agreement dated October 15, 1999, among Northstar Energy Corporation and Devon Energy Corporation, as Canadian Borrowers, Bank of America Canada, as Administrative Agent Bank of America Securities, LLC, as Lead Arranger, BancOne Capital Markets, Inc., as Syndication Agent, The Chase Manhattan Bank, as Documentation Agent, First Union
109

       National Bank, as Co-Documentation Agent, and
       Certain Financial Institutions, as Lenders
       (incorporated by reference to Exhibit 10.2 to
       Registrant's Form 10-Q filed on November 8, 1999).

10.3   Morrison Petroleums Ltd. U.S. $75,000,000 6.76%
       Senior Notes Due July 19, 2005 Note Agreement dated
       as of July 19, 1995 (incorporated by reference to
       Exhibit 10.3 to Devon Energy Corporation
       (Oklahoma)'s (predecessor of Registrant) Form 10-K
       filed on March 31, 1999.)

10.4   Northstar Energy Corporation U.S. $150,000,000 6.79%
       Senior Notes Due 2009 Note Agreement dated as of
       March 2, 1998 (incorporated by reference to Exhibit
       10.4 to Devon Energy Corporation (Oklahoma)'s
       (predecessor of Registrant) Form 10-K filed on March
       31, 1999).

10.5   Pennzoil Company 1990 Stock Option Plan
       (incorporated by reference to Exhibit A to Pennzoil
       Company's definitive proxy material filed on April
       26, 1990, (SEC File No. 1-5591).*

10.6   Pennzoil Company 1990 Conditional Stock Award
       Program (incorporated by reference to Exhibit B to
       Pennzoil Company's definitive proxy material filed
       on April 26, 1990, SEC File No. 1-5591).*

10.7   Pennzoil Company 1992 Stock Option Plan
       (incorporated by reference to Exhibit A to Pennzoil
       Company definitive proxy material filed on April 13,
       1993, SEC File No. 1-5591).*

10.8   Pennzoil Company 1993 Conditional Stock Award
       Program (incorporated by reference to Exhibit B to
       Pennzoil Company's definitive proxy material filed
       on April 13, 1993, SEC File No. 1-5591). *

10.9   Pennzoil Company 1997 Incentive Plan (incorporated
       by reference to Exhibit A to Pennzoil Company
       definitive proxy material filed on March 21, 1997,
       SEC File No. 1-5591).*

10.10  PennzEnergy Company 1998 Incentive Plan
       (incorporated by reference to Exhibit 4.3 to
       Pennzoil Company's Form S-8 filed on December 29,
       1998 SEC No. 333-69845).*

                 110	

10.11  Devon Energy Corporation 1988 Stock Option Plan
       (incorporated by reference to Exhibit 10.4 to Devon
       Energy Corporation (Oklahoma)'s (predecessor of
       Registrant) Registration Statement on Form S-4 filed
       on July 15, 1999, SEC File No. 33-23564).*

10.12  Devon Energy Corporation 1993 Stock Option Plan
       (incorporated by reference to Exhibit A to Devon
       Energy Corporation (Oklahoma)'s (predecessor to
       Registrant) Proxy Statement for the 1993 Annual
       Meeting of Shareholders filed on May 6, 1993).*

10.13  Devon Energy Corporation 1997 Stock Option Plan
       (incorporated by reference to Exhibit A to Devon
       Energy Corporation (Oklahoma)'s (predecessor to
       Registrant) Proxy Statement for the 1997 Annual
       Meeting of Shareholders filed on April 3, 1997).*

10.14  Employment Agreement between Devon Energy
       Corporation (Nevada), Registrant and Duke R. Ligon,
       dated February 7, 1997 (incorporated by reference to
       Exhibit 10.12 to Devon Energy Corporation
       (Oklahoma)'s (predecessor to Registrant) Form 10-Q
       filed on July 22, 1997).*

10.15  Amendment to Supplemental Retirement Income
       Agreement among Devon Energy Corporation (Nevada),
       Registrant and John W. Nichols, dated September 30,
       1999.*

10.16  Supplemental Retirement Income Agreement among Devon
       Energy Corporation (Nevada), Registrant and John W.
       Nichols, dated March 26, 1997 (incorporated by
       reference to Exhibit 10.13 to Devon Energy
       Corporation (Oklahoma)'s (predecessor to Registrant)
       Form 10-Q filed on July 22, 1997).*

10.17  Supplemental Benefit Agreement between Northstar
       Energy Corporation and John A. Hagg dated February
       17, 1999 (incorporated by reference to Exhibit 10.15
       to Devon Energy Corporation (Oklahoma)'s
       (predecessor to Registrant) Annual Report on Form
       10-K filed on March 31, 1999).*	

111

10.18  Severance Agreement between Devon Energy Corporation
       (Nevada), Devon Energy Corporation, Devon Delaware
       Corporation and J. Larry Nichols, dated May 19, 1999
       (incorporated by reference to Exhibit 10.4 to
       Registrant's Form 10-Q filed on November 8, 1999).*

10.19  Form of Severance Agreement between Devon Energy
       Corporation (Nevada), Devon Energy Corporation,
       Devon Delaware Corporation and J. Michael Lacey,
       Marian J. Moon, Duke R. Ligon, Darryl G. Smette, H.
       Allen Turner and William T. Vaughn, dated May 19,
       1999 (incorporated by reference to Exhibit 10.3 to
       Registrant's Form 10-Q filed on November 8, 1999).*

10.20  Director's Restricted Stock Award Agreement between
       Devon Delaware Corporation (predecessor to
       Registrant) and James L. Pate, dated August 17,
       1999.*

10.21  Consulting Agreement between Registrant (as
       successor by merger to PennzEnergy) and Brent
       Scowcroft dated May 17, 1999.*

10.22  Sale and Purchase Agreement relating to Registrant's
       San Juan Basin gas properties (incorporated by
       reference to Exhibit 10.15 to Devon Energy
       Corporation (Oklahoma)'s (predecessor to Registrant)
       Form 10-Q filed on November 9, 1995).

10.23  Second Restatement of and Amendment to Sale and
       Purchase Agreement relating to Registrant's San Juan
       Basin gas properties (incorporated by reference to
       Exhibit 10.16 to Devon Energy Corporation
       (Oklahoma)'s (predecessor to Registrant) Form 10-Q
       filed on November 9, 1995).

12     Computation of ratio of earnings to fixed charges

21     Subsidiaries of Registrant

23.1   Consent of LaRoche Petroleum Consultants, Ltd.

23.2   Consent of AMH Group, Ltd.

23.3   Consent of Paddock Lindstrom & Associates Ltd.

23.4   Consent of KPMG LLP

23.5   Consent of Ryder-Scott Company Petroleum Consultants

23.6   Consent of Deloitte & Touche LLP

27     Financial Data Schedule (filed electronically only)	

* Compensatory plans or arrangements.
Reports on Form 8-K - A Current Report on Form 8-K dated January 26, 2000, was filed by the Registrant regarding year-end 1999 oil and gas reserves and 2000 forward-looking information.
112

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
DEVON ENERGY CORPORATION

March 28, 2000                           By  /s/ J. Larry Nichols
                                             ---------------------------
                                             J. Larry Nichols, President	

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

March 28, 2000                           By  /s/ James L. Pate
                                             ------------------------
                                             James L. Pate
                                             Chairman of the Board and Director

March 28, 2000                           By  /s/ J. Larry Nichols
                                             ---------------------------
                                             J. Larry Nichols
                                             President, Chief Executive Officer
                                             and Director

March 28, 2000                           By  /s/ William T. Vaughn
                                             ----------------------------
                                             William T. Vaughn
                                             Senior Vice President - Finance

March 28, 2000                           By  /s/ Danny J. Heatly
                                             --------------------------
                                             Danny J. Heatly
                                             Vice President - Accounting	

113

March 28, 2000                           By  /s/ Thomas F. Ferguson
                                             -----------------------------
                                             Thomas F. Ferguson, Director

March 28, 2000                           By  /s/ David M. Gavrin
                                             --------------------------
                                             David M. Gavrin, Director

March 28, 2000                           By  /s/ Michael E. Gellert
                                             -----------------------------
                                             Michael E. Gellert, Director

March 28, 2000                           By  /s/ Moulton Goodrum, Jr.
                                             -------------------------------
                                             Moulton Goodrum, Jr., Director

March 28, 2000                           By  /s/ John A. Hagg
                                             -----------------------
                                             John A. Hagg, Director

March 28, 2000                           By  /s/ Henry R. Hamman
                                             --------------------------
                                             Henry R. Hamman, Director

March 28, 2000                           By  /s/ William J. Johnson
                                             -----------------------------
                                             William J. Johnson, Director

March 28, 2000                           By  /s/ Michael M. Kanovsky
                                             ------------------------------
                                             Michael M. Kanovsky, Director

March 28, 2000                           By  /s/ Robert Mosbacher, Jr.
                                             --------------------------------
                                             Robert Mosbacher, Jr., Director

March 28, 2000                           By  /s/ H. R. Sanders, Jr.
                                             -----------------------------
                                             H. R. Sanders, Jr., Director

March 28, 2000                           By  /s/ Brent Scowcroft
                                             Brent Scowcroft, Director

March 28, 2000                           By  /s/ Robert B. Weaver
                                             ---------------------------
                                             Robert B. Weaver, Director	

114

INDEX TO EXHIBITS

Exhibit                                                                     Page
-------                                                                     ----
2.1    Amended and Restated Agreement and Plan of Merger among
       Registrant, Devon Energy Corporation (Oklahoma) (formerly Devon
       Energy Corporation, an Oklahoma corporation), Devon Oklahoma
       Corporation and PennzEnergy Company dated as of May 19, 1999.......... *

2.2    Amended and Restated Combination Agreement between the Registrant
       and Northstar Energy Corporation dated as of June 29, 1998.............*

3.1    Registrant's Restated Certificate of Incorporation.....................*

3.2    Registrant's Bylaws....................................................*

4.1    Form of Common Stock Certificate.......................................*

4.2    Rights Agreement dated as of August 17, 1999 between Registrant
       and BankBoston, N.A....................................................*

4.3    Certificate of Designations of Series A Junior Participating
       Preferred Stock of Registrant..........................................*

4.4    Certificate of Designations of the 6.49% Cumulative Preferred
       Stock, Series A of Registrant..........................................*	

115

4.5    Description of Capital Stock of Registrant.............................*

4.6    Indenture dated as of December 15, 1992 between Registrant
       (as successor by merger to PennzEnergy, successor to Pennzoil
       Company) and Texas Commerce Bank National Association, Trustee.........*

4.7    Third Supplemental Indenture dated as of August 3, 1998 to
       Indenture dated as of December 15, 1992 among Registrant (as
       successor by merger to PennzEnergy) and Chase Bank of Texas,
       National Association, setting forth the terms of the 4.90%
       Exchangeable Senior Debentures due August 15, 2008.....................*

4.8    Fourth Supplemental Indenture dated as of August 3, 1998 to
       Indenture dated as of December 15, 1992 among Registrant (as
       successor by merger to PennzEnergy) and Chase Bank of Texas,
       National Association, setting forth the terms of the 4.95%
       Exchangeable Senior Debentures due August 15, 2008.....................*

4.9    Fifth Supplemental Indenture dated as of August 17, 1999 to
       Indenture dated as of December 15, 1992 among Registrant (as
       successor by merger to PennzEnergy) and Chase Bank of Texas,
       National Association...................................................*

4.10   Indenture dated as of February 15, 1986 among Registrant
       (as successor by merger to PennzEnergy, as successor to
       Pennzoil Company) and Chase Bank of Texas, National
       Association............................................................*

4.11   First Supplemental Indenture dated as of August 17, 1999 to
       Indenture dated as of February 15, 1986 among Registrant (as
       successor by merger to PennzEnergy) and Chase Bank of Texas,
       National Association...................................................*

4.12   Second Supplemental Indenture dated as of August 17, 1999 to
       Indenture dated as of July 3, 1996 among the Registrant and
       The Bank of New York, as Trustee and the First Supplemental
       Indenture dated as of July 3, 1996 between the Registrant
       and The Bank of New York, as Trustee, relating to the issuance
       of 6.5% Trust Convertible Preferred Junior Subordinated
       Debentures.............................................................*	

116

4.13   Amending Support Agreement dated as of August 17, 1999 between
       Registrant and Northstar Energy Corporation............................*

4.14   Support Agreement, dated December 10, 1998, between the Registrant
       and Northstar Energy Corporation.......................................*

4.15   Registration Rights Agreement, dated December 31, 1996, by and
       between Registrant and Kerr-McGee Corporation..........................*

4.16   Exchangeable Share Provisions..........................................*

4.17   Amended Exchangeable Share Provisions dated as of
       August 17, 1999......................................................121

9.1    Voting and Exchange Trust Agreement, dated December 10, 1998, by
       and between Registrant, Northstar Energy Corporation and CIBC
       Mellon Trust Company...................................................*

9.2    Amending Voting and Exchange Trust Agreement, dated as of August
       17, 1999, by and between Registrant, Northstar Energy Corporation
       and CIBC Mellon Trust Company..........................................*

10.1   U.S. Credit Agreement, dated October 15, 1999 among the
       Registrant, as U.S. Borrower, Bank of America, N.A., as
       Administrative Agent, Bank of America Securities, LLC, as Lead
       Arranger, Bank One, Texas, N.A., as Syndication Agent, The Chase
       Manhattan Bank, as Documentation Agent, First Union National Bank,
       as Co-Documentation Agent, and Certain Financial Institutions,
       as Lenders.............................................................*

10.2   Canadian Credit Agreement dated October 15, 1999, among Northstar
       Energy Corporation and Devon Energy Corporation, as Canadian
       Borrowers, Bank of America Canada, as Administrative Agent, Bank
       of America Securities, LLC, as Lead Arranger, BancOne Capital
       Markets, Inc., as Syndication Agent, The Chase Manhattan Bank, as
       Documentation Agent, First Union National Bank, as
       Co-Documentation Agent, and Certain Financial Institutions,
       as Lenders.............................................................*

10.3   Morrison Petroleums Ltd. U.S. $75,000,000 6.76% Senior Notes Due
       July 19, 2005 Note Agreement dated as of July 19, 1995.................*	

117

10.4   Northstar Energy Corporation U.S. $150,000,000 6.79% Senior Notes
       Due 2009 Note Agreement dated as of March 2, 1998......................*

10.5   Pennzoil Company 1990 Stock Option Plan................................*

10.6   Pennzoil Company 1990 Conditional Stock Award Program..................*

10.7   Pennzoil Company 1992 Stock Option Plan................................*

10.8   Pennzoil Company 1993 Conditional Stock Award Program..................*

10.9   Pennzoil Company 1997 Incentive Plan...................................*

10.10  PennzEnergy Company 1998 Incentive Plan................................*

10.11  Devon Energy Corporation 1988 Stock Option Plan........................*

10.12  Devon Energy Corporation 1993 Stock Option Plan........................*

10.13  Devon Energy Corporation 1997 Stock Option Plan........................*

10.14  Employment Agreement between Devon Energy Corporation (Nevada),
       Registrant and Duke R. Ligon, dated February 7, 1997.................. *

10.15  Amendment to Supplemental Retirement Income Agreement among Devon
       Energy Corporation (Nevada), Registrant and John W. Nichols, dated
       September 30, 1999...................................................122

10.16  Supplemental Retirement Income Agreement among Devon Energy
       Corporation (Nevada), Registrant and John W. Nichols, dated
       March 26, 1997.........................................................*

10.17  Supplemental Benefit Agreement between Northstar Energy
       Corporation and John A. Hagg dated February 17, 1999...................*

10.18  Severance Agreement between Devon Energy Corporation (Nevada),
       Devon Energy Corporation, Devon Delaware Corporation and J. Larry
       Nichols, dated May 19, 1999............................................*	

118

10.19  Form of Severance Agreement between Devon Energy Corporation
       (Nevada), Devon Energy Corporation, Devon Delaware Corporation and
       J. Michael Lacey, Marian J. Moon, Duke R. Ligon, Darryl G. Smette,
       H. Allen Turner and William T. Vaughn, dated May 19, 1999..............*

10.20  Director's Restricted Stock Award Agreement between Devon Delaware
       Corporation (predecessor to Registrant) and James L. Pate, dated
       August 17, 1999......................................................123

10.21  Consulting Agreement between Registrant (as successor to merger to
       PennzEnergy) and Brent Scowcroft dated May 17, 1999..................129

10.22  Sale and Purchase Agreement relating to Registrant's San Juan
       Basin gas properties...................................................*

10.23  Second Restatement of and Amendment to Sale and Purchase Agreement
       relating to Registrant's San Juan Basin gas properties.................*

12     Computation of ratio of earnings to fixed charges....................131

21     Subsidiaries of Registrant...........................................132

23.1   Consent of LaRoche Petroleum Consultants, Ltd........................134

23.2   Consent of AMH Group, Ltd............................................135

23.3   Consent of Paddock Lindstrom & Associates Ltd........................136	

119

23.4   Consent of KPMG LLP..................................................137

23.5   Consent of Ryder-Scott Company Petroleum Consultants.................138

23.6   Consent of Deloitte & Touche LLP.....................................139

27     Financial Data Schedule (filed electronically only)	

*Incorporated by reference.
120

EXHIBIT 4.17
AMENDED EXCHANGEABLE SHARE PROVISIONS
DATED AS OF AUGUST 17, 1999
SCHEDULE OF OTHER PROVISIONS
The board of directors of the Corporation may, between annual general meetings, appoint one or more additional directors of the Corporation to serve until the next annual general meeting, but the number of additional directors shall not at any time exceed one third (1/3) of the number of directors who held office at the expiration of the last annual general meeting of the Corporation.
The Plan of Arrangement made effective December 10, 1998 under Section 186 of the Business Corporations Act (Alberta) be and the same is hereby amended in accordance with Section 167(1)(m) of the Business Corporations Act (Alberta) by deleting the definition of "Devon" in Section 1.1 thereof and replacing it with the following:
"Devon" has the meaning provided in the Exchangeable Share Provisions
121

EXHIBIT 10.15
AMENDMENT TO SUPPLEMENTAL RETIREMENT INCOME AGREEMENT
THIS AMENDMENT TO SUPPLEMENTAL RETIREMENT INCOME AGREEMENT ("Amendment") is entered into as of the 30th day of September, 1999 by and between Devon Energy Corporation, a Delaware corporation (the "Corporation") and John W. Nichols (the "Executive").
WITNESSETH:
WHEREAS, the Corporation and the Executive have previously entered into that certain Supplemental Retirement Income Agreement dated March 26, 1997 (the "Agreement"), which provided that the Corporation would provide to the Executive a "supplemental retirement income" pursuant to the terms of the Agreement; and
WHEREAS, the parties desire to amend the Agreement to increase the amount of the supplemental retirement income provided under the Agreement.
NOW, THEREFORE, for good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree that Section 1 of the Agreement shall be amended to add the following sentence:
"Provided, however, effective October 1, 1999, the annual Supplemental Retirement Income shall be increased from $180,000 to $200,000, and the equal monthly installments of Supplemental Retirement Income will be increased from $15,000 to $16,666.66."
IN WITNESS WHEREOF, the parties have executed this Amendment as of the day and year first above written.

"Corporation"                           DEVON ENERGY CORPORATION, a Delaware
                                        corporation

                                        By  /s/ J. Larry Nichols
                                           -----------------------------------
                                           J. Larry Nichols, President and
                                           Chief Executive Officer

"Executive"                                 /s/ John W. Nichols
                                           -----------------------------------
                                           John W. Nichols	

122

EXHIBIT 10.20
DEVON DELAWARE CORPORATION
DIRECTOR'S RESTRICTED STOCK AWARD AGREEMENT
THIS AGREEMENT ("Agreement") is made as of the 17th day of August, 1999, by and between Devon Delaware Corporation, a Delaware corporation (the "Company"), and James L. Pate (the "Grantee").
The Company and the Grantee therefore agree as follows:
1. GRANT OF RESTRICTED STOCK. Effective as of the Effective Time of the merger of PennzEnergy Company into the Company, as defined in that certain Amended and Restated Agreement and Plan of Merger by and among Devon Energy Corporation, Devon Delaware Corporation, Devon Oklahoma Corporation and PennzEnergy Company, dated as of May 19, 1999 (the"Date of Grant"), the Company has awarded to the Grantee a total of 15,000 shares of Common Stock, subject to the conditions and restrictions set forth below (the "Restricted Stock").
2. RESTRICTIONS. The shares of Restricted Stock granted hereunder to the Grantee may not be sold, assigned, transferred, pledged or otherwise encumbered from the Date of Grant until the date that the Grantee obtains a vested right to the shares (and the restrictions thereon terminate) in accordance with the provisions of this Section 2 or as otherwise provided in
Section 6 below. (The period of time between the Date of Grant and the date that the Grantee obtains a vested right to shares of Restricted Stock shall be referred to herein as the "Restricted Period" as to those shares of stock.) In the event that any day on which the Grantee would otherwise obtain a vested right to additional shares of Restricted Stock is a Saturday, Sunday or holiday, the Grantee shall instead obtain that vested right on the first business day immediately following such date. The Grantee shall have a vested right to the number of shares of Restricted Stock indicated below as of the dates set forth below, provided that the Grantee has not resigned as a Director of the Company since the Date of Grant:

                             Number of
    Date                Shares First Vested
----------              -------------------
May 1, 2000                    5,000
May 1, 2001                    5,000
May 1, 2002                    5,000	

All of the foregoing provisions of this Section 2 are subject to the provisions of Section 6 below, addressing an event that may result in forfeiture of the Grantee's interest in all or part of the Restricted Shares.
123

3. NO CODE SECTION 83(b) ELECTION. The Grantee shall not make an election, under Code Section 83(b), to include an amount in income in respect of the Restricted Stock.
4. SALE OF RESTRICTED STOCK. The Grantee agrees that the Grantee shall not sell, transfer or dispose of the Restricted Stock and that the Company shall not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such sale, transfer, disposition or delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.
5. ESCROW OF SHARES. Shares of Restricted Stock shall be registered in the name of the Grantee and deposited with the Secretary of the Company, together with a stock power endorsed by the Grantee in blank. Any certificate shall bear a legend as provided by the Company, conspicuously referring to the terms, conditions and restrictions described in this Agreement. Upon termination of the Restricted Period with respect to shares of Restricted Stock, a certificate representing such shares shall be delivered upon written request to the Grantee as promptly as is reasonably practicable following such termination.
6. FORFEITURE. If the Grantee's service as Chairman of the Board of Directors of the Company shall terminate for any reason other than voluntary resignation (excluding a resignation at the request of the Board of Directors) prior to all shares of Restricted Stock having become vested pursuant to the provisions of Section 2 hereof, all such shares of Restricted Stock shall immediately be fully vested. If the Grantee shall resign voluntarily from the Board of Directors (excluding a resignation at the request of the Board of Directors) prior to vesting in any portion of the shares of Restricted Stock, the Grantee shall forfeit all right to those unvested shares of Restricted Stock unless otherwise determined by the Board.
7. BENEFICIARY DESIGNATIONS. The Grantee shall file with the Secretary of the Company on the form appended to this Agreement as Exhibit A or such other form as may be prescribed by the Company, a designation of one or more beneficiaries (each, a "Beneficiary") to whom shares otherwise due to the Grantee shall be distributed in the event of the death of the Grantee while serving as a Director of the Company. The Grantee shall have the right to change the Beneficiary or Beneficiaries from time to time; provided, however, that any change shall not become effective until received in writing by the Secretary of the Company. If any designated Beneficiary survives the Grantee but dies before receiving all of the Grantee's benefits hereunder, any remaining benefits due the Grantee shall be distributed to the deceased Beneficiary's estate. If there is no effective Beneficiary designation on file with the Secretary of the Company at the time of the Grantee's death, or if the designated Beneficiary or Beneficiaries have all predeceased such Grantee, the payment of any remaining benefits shall be made to the Grantee's estate.
124

8. NONALIENATION OF BENEFITS. Except as contemplated by Section 7 above, and other than pursuant to a qualified domestic relations order, no right or benefit under this Agreement shall be subject to transfer, anticipation, alienation, sale, assignment, pledge, encumbrance or charge, whether voluntary, involuntary or by operation of law, and any attempt to transfer, anticipate, alienate, sell, assign, pledge, encumber or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to any debts, contracts, liabilities or torts of the person entitled to such benefits. If the Grantee or the Grantee's Beneficiary hereunder shall become bankrupt or attempt to transfer, anticipate, alienate, assign, sell, pledge, encumber or charge any right or benefit hereunder, other than as contemplated by Section 7 above or other than pursuant to a qualified domestic relations order, or if any creditor shall attempt to subject the same to a writ of garnishment, attachment, execution, sequestration or any other form of process or involuntary lien or seizure, then such right or benefit shall cease and terminate.
9. PREREQUISITES TO BENEFITS. Neither the Grantee nor any person claiming through the Grantee shall have any right or interest in the Restricted Stock awarded hereunder, unless and until all the terms, conditions and provisions of this Agreement which affect the Grantee or such other person shall have been complied with as specified herein.
10. RIGHTS AS A STOCKHOLDER. Subject to the limitations and restrictions contained herein, the Grantee (or Beneficiary) shall have all rights as a stockholder with respect to the shares of the Restricted Stock once such shares have been registered in the Grantee's name or issued for the benefit of the Grantee hereunder.
11. ADJUSTMENTS. Appropriate adjustments shall be made to the Restricted Stock upon the occurrence of (i) a reclassification, subdivision, combination or dividend of the Company's Common Stock or (ii) a consolidation or merger with or into, or lease transfer or sale of substantially all the Company's assets to another entity.
12. NOTICE. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be:
(a) delivered personally to the following address:
Devon Delaware Corporation Corporate Secretary 20 North Broadway, Suite 1500 Oklahoma City, Oklahoma
or
125

(b) sent by first class mail, postage prepaid and addressed as follows:
Devon Delaware Corporation Attention: Corporate Secretary 20 North Broadway, Suite 1500 Oklahoma City, OK 73102-8260
Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally or shall be sent by first class mail, postage prepaid, to the Grantee's address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address.
13. AMENDMENT. This Agreement may be amended, provided, however, that an amendment shall not adversely affect the rights of the Grantee with respect to the Award evidenced hereby without the Grantee's written consent.
14. GRANTEE SERVICE. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the service of the Company as a Director.
15. SUCCESSORS AND ASSIGNS. This Agreement shall bind and enure to the benefit of and be enforceable by the Grantee, the Company and their respective permitted successors and assigns (including personal representatives, heirs and legatees), except that the Grantee may not assign any rights or obligations under this Agreement except to the extent and in a manner expressly provided herein.
16. GOVERNING LAW. This Agreement shall in all respects be governed by, and construed and enforced in accordance with, the laws of the State of Delaware to the extent not preempted by federal law.
17. CONSTRUCTION. References in this Agreement to "this Agreement" and the words "herein," "hereof," "hereunder" and similar terms include all Exhibits appended hereto. The headings of the Sections of this Agreement have been included for convenience of reference only and are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.
18. DUPLICATE ORIGINALS. The Company and the Grantee may sign any number of copies of this Agreement. Each signed copy shall be an original, but all of them together represent the same agreement.
19. ENTIRE AGREEMENT. The Grantee and the Company hereby declare and represent that no promise or agreement not herein expressed has been made and that this Agreement contains the entire agreement between the parties hereto with respect to the
126

Restricted Stock granted herein and replaces and makes null and void any prior agreements, oral or written, between the Grantee and the Company regarding the Restricted Stock award.
20. GRANTEE ACCEPTANCE. The Grantee shall signify acceptance of the terms and conditions of this Agreement by signing in the space provided at the end hereof and returning an executed copy to the Company.
DEVON DELAWARE CORPORATION

By:  /s/ J. Larry Nichols
    ------------------------------------------
    Name: J. Larry Nichols
          ------------------------------------
    Title: President & Chief Executive Officer
          ------------------------------------	

ACCEPTED:

/s/ James L. Pate
----------------------------------------------
Grantee:  James L. Pate	

127

Exhibit A to Director's Restricted Stock Award Agreement, dated as of August ____, 1999
DEVON DELAWARE CORPORATION
DESIGNATION OF BENEFICIARY
I, ___________________________________ (the "Grantee"), hereby declare
that upon my death _____________________________________ (the "Beneficiary") of Name
______________________________________________________________________________, Street Address City State Zip Code
who is my ___________________________________________, shall be entitled to the Relationship to the Grantee
Restricted Stock and all other rights accorded the Grantee by the above-referenced grant agreement (the "Agreement").
It is understood that this Designation of Beneficiary is made pursuant to the Agreement and is subject to the conditions stated therein, including the Beneficiary's survival of the Grantee's death. If any such condition is not satisfied, such rights shall devolve according to the Grantee's will or the laws of descent and distribution.
It is further understood that all prior designations of beneficiary under the Agreement are hereby revoked and that this Designation of Beneficiary may only be revoked in writing, signed by the Grantee and filed with the Company prior to the Grantee's death.

Date Grantee

128

EXHIBIT 10.21
CONSULTING AGREEMENT
The following represents the agreement between PennzEnergy Company ("PennzEnergy") and Brent Scowcroft ("Consultant") regarding consulting services.
1. Consultant will provide consulting services as requested by PennzEnergy during the period of June 1, 1999 through May 31, 2002. These consulting services will primarily relate to PennzEnergy's international projects and investments.
2. In exchange for these services, PennzEnergy will pay a retainer in the total amount of $300,000, payable in twelve (12) equal quarterly installments of $25,000, due and payable on the first day of the months of June, September, December and March, with the initial installment payable on June 1, 1999 and the last installment payable on March 1, 2002.
3. In addition, PennzEnergy will either provide transportation and lodging or reimburse Consultant for necessary travel expenses incurred in connection with rendering consulting services pursuant to this agreement.
4. While providing the consulting services contemplated by this agreement, Consultant will be acting as an independent contractor, and not as an employee of PennzEnergy under the meaning of any federal, state or local law.
5. Consultant will be responsible for all taxes and other payments due any federal, state or local government agency with respect to the quarterly retainer payments paid to Consultant by PennzEnergy. PennzEnergy will not withhold taxes or other amounts from the quarterly retainer payments and will not provide any worker's compensation, insurance or other benefits pursuant to this consulting agreement.
129

6. Either party may terminate this agreement at any time upon written notice; however, Consultant will be entitled to reimbursement for travel expense incurred in connection with consulting services performed prior to receipt of the written notice and the retainer will not be subject to refund to the extent one or more quarterly installments have been paid prior to termination. In the event of termination by PennzEnergy, any quarterly installment(s) not previously paid will become due and payable within 30 days following notice of termination.
Agreed to this 17th day of May, 1999.

/s/ James L. Pate                                    /s/ Brent Scowcroft
------------------------------------                 -------------------
By: James L. Pate                                    Brent Scowcroft
Title: Chairman of the Board                         900 Seventeenth St., N.W.
                                                     Suite 500
                                                     Washington, DC 20006	

130

EXHIBIT 12
DEVON ENERGY CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

                                                                             YEAR DECEMBER 31,
                                                                  -----------------------------------
                                                                     1999         1998         1997
                                                                  ---------    ---------    ---------
                                                                      (IN THOUSANDS, EXCEPT RATIOS)
Earnings (loss) before income taxes                                $ 159,722      (75,792)    (473,833)

Add:
     Interest expense                                                 66,913       22,632       18,788
     Distributions on preferred securities of subsidiary               6,884        9,717        9,717
     Amortization of costs incurred in connection with
       the offering of the preferred securities of
       subsidiary trust                                                  148          240          269
     Amortization of premium on debentures                            (1,328)          --           --
     Estimated interest factor of operating lease payments             2,069          683          505
     Deferred effect of changes in foreign currency exchange
       rate on subsidiary's long-term debt                           (13,154)      16,104        5,860
     Dividends on preferred stock                                      5,889           --           --
                                                                   ---------    ---------    ---------

Earnings (loss) as adjusted (A)                                    $ 227,143      (26,416)    (438,694)
                                                                   =========    =========    =========

Fixed charges:
     Interest costs incurred                                          66,913       22,632       18,788
     Distributions on preferred securities of subsidiary trust         6,884        9,717        9,717
     Amortization of costs incurred in connection with
       the offering of the preferred securities of
       subsidiary trust                                                  148          240          269
     Amortization of premium on debentures                            (1,328)          --           --
     Estimated interest factor of operating lease payments             2,069          683          505
     Deferred effect of changes in foreign currency exchange
       rate on subsidiary's long-term debt                           (13,154)      16,104        5,860
     Dividends on preferred stock                                      5,889           --           --
                                                                   ---------    ---------    ---------

Total fixed charges (B)                                            $  67,421       49,376       35,139
                                                                   =========    =========    =========

Ratio of earnings to fixed charges (A)/(B)                              3.37          N/A          N/A
                                                                   =========

Insufficiency of earnings to cover fixed charges                         N/A       75,792      473,833
                                                                                =========    =========	

131

EXHIBIT 21
DEVON ENERGY CORPORATION
SUBSIDIARIES

1.       661151 ALBERTA LTD., ALBERTA
2.       410760 ALBERTA LTD., ALBERTA
3.       659502 ALBERTA INC., ALBERTA
4.       728098 ALBERTA LTD., ALBERTA
5.       172173 CANADA, INC.
6.       AMERICAN SULPHUR EXPORT CORPORATION
7.       AMSULEX, INC.
8.       AZERBAIJAN INTERNATIONAL OPERATING COMPANY
9.       BONITO PIPE LINE COMPANY
10.      CACHUMA GAS PROCESSING COMPANY
11.      CANOA RANCH CORPORATION
12.      CANYON REEF CARRIERS, INC.
13.      CAPITAN OIL PIPELINE COMPANY
14.      CASPIAN INTERNATIONAL PETROLEUM COMPANY
15.      CATCLAW PIPELINE, INC.
16.      DBC, INC.
17.      DAVID LIMITED PARTNERSHIP, ALBERTA
18.      DEVON ACQUISITION CORPORATION
19.      DEVON ENERGY CANADA LTD., ALBERTA
20.      DEVON ENERGY CANADA CORPORATION, ALBERTA
21.      DEVON ENERGY CANADA HOLDING CORPORATION, ALBERTA
22.      DEVON ENERGY CORPORATION (DELAWARE)
23.      DEVON ENERGY CORPORATION (NEVADA)
24.      DEVON ENERGY CORPORATION (OKLAHOMA)
25.      DEVON ENERGY MANAGEMENT COMPANY, L. L. C.
26.      DEVON ENERGY PRODUCTION COMPANY, L. P.
27.      DEVON FINANCING TRUST
28.      DEVON OIL & GAS COMPANY
29.      DEVON PRODUCTION CORPORATION
30.      FOOTHILLS PARTNERSHIP, ALBERTA
31.      MORRISON NUCLEAR LTD., DELAWARE
32.      MORRISON PETROLEUMS, LTD.
33.      MOUNTAIN ENERGY INC., ALBERTA
34.      NORTHSTAR ENERGY CORPORATION, ALBERTA
35.      NORTHSTAR ENERGY PARTNERSHIP, ALBERTA
36.      NUECES INTRASTATE PIPE LINE COMPANY
37.      PENNZENERGY BRAZIL, LTDA.
38.      PENNZENERGY COMPANY
39.      PENNZENERGY EXPLORATION AND PRODUCTION, L. L. C.
40.      PENNZENERGY INSURANCE COMPANY LIMITED (BERMUDA)
41.      PENNZENERGY RECEIVABLES COMPANY
42.      PENNZENERGY (U.K.) COMPANY
43.      PENNZOIL ASIATIC, INC.
44.      PENNZOIL BENI SUEF, INC.
45.      PENNZOIL CASPIAN CORPORATION
46.      PENNZOIL CASPIAN DEVELOPMENT CORPORATION
47.      PENNZOIL EGYPT, INC.
48.      PENNZOIL ENERGY MARKETING COMPANY
49.      PENNZOIL EXPLORATION AUSTRALIA, INC.
50.      PENNZOIL EXPLORATION BRAZIL, INC.	

132

51.      PENNZOIL GAS MARKETING COMPANY
52.      PENNZOIL INTERNATIONAL COMPANY
53.      PENNZOIL INTRASTATE PIPELINE COMPANY
54.      PENNZOIL OFFSHORE PIPELINE COMPANY
55.      PENNZOIL PETROLEUM PIPELINE COMPANY
56.      PENNZOIL PETROLEUMS, LTD.
57.      PENNZOIL QATAR, INC.
58.      PENNZOIL QATAR PRODUCTION, INC.
59.      PENNZOIL RESOURCES CANADA LTD.
60.      PENNZOIL RED SEA, INC.
61.      PENNZOIL SINAI, INC.
62.      PENNZOIL SUEZ, INC.
63.      PENNZOIL VENEZUELA CORPORATION, S. A.
64.      PEPCO PARTNERS, L. P.
65.      RICHLAND DEVELOPMENT CORPORATION
66.      RICHLAND TRANSITION COMPANY
67.      SAGE CREEK, INC.
68.      SISQUOC GAS PIPELINE COMPANY
69.      THUNDER CREEK, INC.
70.      TIBURON TRANSPORT COMPANY
71.      VERMEJO MINERALS CORPORATION
72.      VERMEJO PARK CORPORATION	

133

EXHIBIT 23.1
ENGINEER'S CONSENT
We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1999, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation.
LAROCHE PETROLEUM CONSULTANTS, LTD.

                                             By: /s/ William M. Kazmann
                                                 ----------------------
                                                     Partner

March 28, 2000	

134

EXHIBIT 23.2
ENGINEER'S CONSENT
We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1998, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation.
AMH GROUP LTD.

                                                  /s/  Allan K. Ashton, P.Eng.
                                                  ----------------------------
                                                       President

March 28, 2000	

135

EXHIBIT 23.3
ENGINEER'S CONSENT
We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1999, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation.
PADDOCK LINDSTROM & ASSOCIATES LTD.

                                        /s/ D.L. Paddock, P. Eng.
                                        -------------------------
                                        D.L. Paddock, P. Eng.
                                        Vice-President

March 28, 2000	

136

EXHIBIT 23.4
INDEPENDENT AUDITORS' CONSENT
The Board of Directors
Devon Energy Corporation:
We consent to incorporation by reference in the Registration Statements (No. 333-32214 and 333-85553) on Form S-8 and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation of our report dated February 9, 2000, relating to the consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 1999, 1998 and 1997 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended, which report appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation.
KPMG LLP
Oklahoma City, Oklahoma
March 27, 2000
137

EXHIBIT 23.5
CONSENT OF RYDER SCOTT COMPANY, L.P.
We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation, the reference to our appraisal report for Devon Energy Corporation as of December 31, 1999, which appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation.

                                             /s/  RYDER SCOTT COMPANY, L.P.

Houston, Texas
March 28, 2000	

138

EXHIBIT 23.6
INDEPENDENT AUDITORS' CONSENT
We consent to incorporation by reference in the Registration Statements (No. 333-32214 and No. 333-85553) on Form S-8, and the Registration Statement (No. 333-85211) on Form S-3 of Devon Energy Corporation and our report dated January 20, 1999 to the shareholders of Northstar Energy Corporation, relating to the consolidated balance sheets of Northstar Energy Corporation and subsidiaries as at December 31, 1998 and 1997 and the related consolidated statements of operations and comprehensive income (loss), stockholders' equity, and cash flows for each of the years then ended, which report appears in the December 31, 1999 annual report on Form 10-K of Devon Energy Corporation.

                                        (SIGNED)  DELOITTE & TOUCHE LLP
                                        -----------------------------------
                                                  Deloitte & Touche LLP
                                                  Chartered Accountants

Calgary, Alberta
Canada
March 28, 2000	

139

ARTICLE 5	

		
PERIOD TYPE	YEAR	YEAR	
FISCAL YEAR END	DEC 31 1999	DEC 31 1998	
PERIOD END	DEC 31 1999	DEC 31 1998	
CASH	167,167	19,154	
SECURITIES	0	0	
RECEIVABLES	209,405	83,858	
ALLOWANCES	0	0	
INVENTORY	13,441	2,750	
CURRENT ASSETS	417,194	110,648	
PP&E	4,974,810	2,610,511	
DEPRECIATION	1,818,890	1,509,583	
TOTAL ASSETS	4,623,160	1,226,356	
CURRENT LIABILITIES	227,444	80,656	
BONDS	1,787,121	405,271	
PREFERRED MANDATORY	0	0	
PREFERRED	1,500	0	
COMMON	8,608	4,842	
OTHER SE	2,015,412	518,121	
TOTAL LIABILITY AND EQUITY	4,623,160	1,226,356	
SALES	715,503	369,660	
TOTAL REVENUES	734,499	387,508	
CGS	0	0	
TOTAL COSTS	0	0	
OTHER EXPENSES	189,903	127,400	
LOSS PROVISION	0	0	
INTEREST EXPENSE	66,913	22,632	
INCOME PRETAX	159,722	(75,792)	
INCOME TAX	65,166	(15,507)	
INCOME CONTINUING	94,556	(60,285)	
DISCONTINUED	0	0	
EXTRAORDINARY	0	0	
CHANGES	0	0	
NET INCOME	94,556	(60,285)	
EPS BASIC	1.51	(1.25)	
EPS DILUTED	1.46	(1.25)