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, 1998
                               OR
      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                SECURITIES EXCHANGE ACT OF 1934
                 Commission File Number 1-10067

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

           Oklahoma                             73-1474008
(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
                           

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 22, 1999, was
$977,270,467.  At such date 42,789,808 shares of common stock and
5,690,651 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 1999 annual meeting of stockholders -  Part III
<PAGE>

                       TABLE OF CONTENTS

                                                             Page

PART I
 Item 1. Business                                              4
 Item 2. Properties                                           11
 Item 3. Legal Proceedings                                    22
 Item 4. Submission of Matters to a Vote of 
           Security Holders                                   22

PART II
 Item 5. Market for Registrant's Common Equity
          and Related Stockholder Matters                     22
 Item 6. Selected Financial Data                              24
 Item 7. Management's Discussion and Analysis of Financial
          Condition and Results of Operations                 27
 Item 8. Financial Statements and Supplementary Data          49
 Item 9. Changes in and Disagreements with Accountants on
          Accounting and Financial Disclosure                104

PART III
 Item 10. Directors and Executive Officers of 
           the Registrant                                    104
 Item 11. Executive Compensation                             104
 Item 12. Security Ownership of Certain Beneficial
           Owners and Management                             104
 Item 13. Certain Relationships and Related
           Transactions                                      104

PART IV
 Item 14. Exhibits, Financial Statement Schedules,
           and Reports on Form 8-K                           105

                          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
<PAGE>
         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 MANAGMENT 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-1998 ESTIMATES", ITEM 2. "PROPERTIES -
PROVED RESERVES AND ESTIMATED FUTURE NET REVENUES" 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.

<PAGE>

                             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
six operating areas: the Permian Basin in southeastern New Mexico
and western Texas; the Rocky Mountain region primarily in
Wyoming; the San Juan Basin region in northwest New Mexico, the
Northern Alberta region in northern Alberta and a portion of
northeastern British Columbia, the Southern Alberta region in
central and southeastern Alberta and southwestern Saskatchewan,
and the Foothills region in southwestern Alberta and northeastern
British Columbia. (A detailed description of the significant
properties can be found under "Item 2. Properties - Significant
Properties" beginning on page 15 hereof.)

     At December 31, 1998, Devon's estimated proved reserves were
299.4 MMBoe, of which 67% were natural gas reserves and 33% were
oil 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 $1.0 billion.
Devon is one of the top 15 public independent oil and gas
companies in both the United States and Canada, 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.

     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.  Approximately two-thirds
of total capital spent during this period was for property
acquisitions and one-third was for drilling.  Total proved
reserves increased from 8.1 MMBoe at year-end 1987 to 299.4 MMBoe
at year-end 1998.

     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 5.61 Boe per diluted share
at year-end 1998.  At the same time, net debt (long-term debt
less working capital) has remained relatively low.  At year-end
1998, Devon's net debt was $1.25 per Boe.


Recent Developments

     On December 10, 1998, Devon completed a merger with Canadian-
based Northstar. Northstar's properties are located primarily in
the Western Canada Sedimentary Basin in the province of Alberta.
The combination of Northstar with Devon (the "Northstar
Combination") expanded Devon's reserves by approximately 115.0
MMBoe, or 62%, and nearly tripled the Company's undeveloped
leasehold inventory. In addition, Devon retained the experienced
Northstar management team to continue to direct the Company's
Canadian operations.  The total consideration to Northstar was
16.1 million common equivalent shares and the assumption of $307
million Northstar debt.  At year-end 1998, Devon's unused
borrowing capacity was in excess of $200 million.

     The Northstar Combination places Devon in a unique position
to take advantage of growth opportunities both in the U.S. and in
Canada. The Company's properties are now relatively balanced,
with 52% of its proved reserves in the U.S. and 48% in Canada.
This provides Devon with considerable exposure to growing North
American natural gas markets, while retaining Devon's historical
exposure to substantial oil reserves, particularly in the Permian
Basin of the U.S.  In addition, the Company owns a large
inventory of acreage and the financial flexibility to pursue the
opportunities for drilling on this acreage.

     The Northstar Combination was accounted for under the
"pooling-of-interests" method of accounting.  Therefore, all of
Devon's operational and financial information was restated to
include the Northstar results as if Devon and Northstar had
always been combined. As a result, unless otherwise indicated,
all of the operational data included hereafter includes results
for both Devon and Northstar combined.


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 1999, Devon's drilling
activities will be focused in the Rocky Mountain and Permian
Basin regions in the U.S. and the Foothills and Northern Alberta
regions of Canada.

     The following tables set forth Devon's drilling results
(including Northstar's historical activities) for the past five
years.
<TABLE>
<CAPTION>
                           United States Properties
                                                        
             Development Wells                 Exploratory Wells
         Gross (1)         Net (2)           Gross (1)        Net (2)
      Produ Dry Tot  Produ  Dry   Tot    Produ  Dry Tot  Produ Dry  Tot
      ctive      al  ctive         al    ctive       al  ctive       al
<C>  <C>   <C><C>   <C>     <C>  <C>      <C>  <C>  <C> <C>    <C>  <C>
1994    77  1    78  44.40  0.28  44.68    2    3    5   0.52  2.37  2.89
                                                               
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
                                                      
TTL  1,021 16 1,037 563.01  6.42 569.43   41   13   54  16.91  6.57 23.48     
</TABLE>
<TABLE>
<CAPTION>
                                                              
                             Canadian Properties
                                                                    
             Development Wells                 Exploratory Wells
         Gross (1)         Net (2)         Gross (1)        Net (2)
      Produ  Dry  Tot  Produ  Dry  Tot    Produ  Dry  Tot  Produ  Dry  Tot      
      ctive        al  ctive        al    ctive        al  ctive        al
                                                            
<C>   <C>   <C>  <C> <C>    <C>   <C>     <C>   <C>  <C> <C>    <C>    <C>
1994  142   19   161  62.50  7.80  70.30   29    12   41  22.50   9.00  31.50
                                                            
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
                                                          
TTL   487   82   569 280.48 52.34 332.82  212   128  340 159.39 106.80 266.19 
</TABLE>
<TABLE>
<CAPTION>
                                                                        
                               Total Properties
                                                                        
             Development Wells                 Exploratory Wells
         Gross (1)         Net (2)         Gross (1)        Net (2)
      Produ Dry  Tot  Produ    Dry  Tot    Produ Dry Tot  Produ  Dry     Tot    
      ctive       al  ctive          al    ctive      al  ctive           al
                                                                       
<C>  <C>    <C><C>    <C>     <C>   <C>     <C> <C> <C>  <C>    <C>     <C>
1994    219 20   239  106.90   8.08 114.98   31  15  46   23.02  11.37   34.39
                                                            
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
                                                             
TTL   1,508 98 1,606  843.49  58.76 902.25  253 141 394  176.30 113.37  289.67
<FN>
(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.
</TABLE>

     As of December 31, 1998, Devon was participating in the
drilling of 33 gross (11.38 net) wells in the U.S. and 9 gross
(5.37 net) wells in Canada which are not included in the table
above.  Through March 22, 1999, 3 gross (0.99 net) wells in the
U.S. and 3 gross (2.17 net) wells in Canada had been completed as
productive.  An additional 1 gross (0.45 net) well in the U.S.
and 4 gross (2.2 net) wells in Canada were dry holes.  The
remaining wells were still in process.

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 years ended December 31, 1998 and December 31, 1997,
one significant purchaser, Aquila Energy Marketing Corporation
("Aquila"), accounted for 19% and 15%, respectively, of Devon's
total revenue.  For the year ended December 31, 1996, two
significant purchasers, Aquila and EOTT Energy Operating Limited
Partnership ("Enron"), accounted for 12% and 15%, respectively,
of Devon's total revenue.  Aquila and Enron 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 production at competitive prices.

Oil and Natural Gas Marketing

     Oil Marketing.  Devon's oil production is sold under both
long- 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- and short-term agreements at negotiated prices.
Although exact percentages vary daily, as of March, 1999
approximately 31% 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 36% was committed under various long-term
contracts (one year or more) which dedicate the natural gas to a
purchaser for an extended period of time.  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.")

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 and
Canada.

     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 the 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; submitting and
implementing spill prevention plans; submitting notification
relating to the presence, use and release of certain contaminants
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
prohibit 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.

     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.

     Environmental and Occupational Regulations.  Various
federal, state and local laws and regulations concerning the
discharge of contaminants 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 and
accidental discharges of oil, salt water or other harmful
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 1998
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.

     In 1992 Devon retained the services of an independent
environmental engineering firm to provide a comprehensive
evaluation of Devon's significant properties and to otherwise
advise Devon concerning its compliance with various environmental
laws. In 1993 Devon established its own internal Environmental
Industrial Hygiene and Safety Department to perform these
functions. 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 audits of Devon's compliance procedures.

     Canadian Regulation

     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 U.S. 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 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 1998 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.

Employees

     As of December 31, 1998, Devon's staff consisted of 764 full-
time employees, including 72 professionals in engineering, 57 in
geology, 44 in the land department, 16 in oil and gas marketing,
98 in accounting and data processing, and 34 in administration
and other support positions. The Company also engages independent
consulting petroleum engineers, 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 New Mexico, Wyoming, Texas, Oklahoma and
Alberta, Canada. 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, royalty, 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, 1998. Approximately 93%
of Devon's U.S. proved reserves were estimated by LaRoche
Petroleum Consultants, Ltd., independent petroleum engineers.
Devon's internal staff of engineers estimated the remainder of
the U.S. reserves.  AMH Group Ltd. and Paddock Lindstrom &
Associates Ltd. calculated all of the Canadian proved reserves.
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 notes
below). 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.
<TABLE>
<CAPTION>
                                           Total          Proved         Proved
                                          Proved       Developed    Undeveloped
                                        Reserves    Reserves (1)   Reserves (2)
TOTAL RESERVES
  <S>                                  <C>             <C>              <C>
  Oil (MBbls)                             83,457          73,846          9,611
  Gas (MMcf)                           1,198,894       1,052,647        146,247
  NGLs (MBbl)                             16,079          15,081            998
  MBoe (3)                               299,352         264,368         34,984
  Pre-tax Future Net Revenue           1,657,020       1,513,064         43,956l
      ($ thousands) (4)
  Pre-tax 10% Present Value            1,009,039         941,701         67,338
      ($ thousands) (4)

U.S. RESERVES
  Oil (MBbls)                             44,451          40,631          3,820
  Gas (MMcf)                             596,987         469,064        127,923
  NGLs (MBbl)                             11,494          10,577            917
  MBoe (3)                               155,443         129,385         26,058
  Pre-tax Future Net Revenue             899,983         780,548        119,435
      ($ thousands) (4)
  Pre-tax 10% Present Value              546,118         490,559         55,559
      ($ thousands) (4)

CANADIAN RESERVES

  Oil (MBbls)                             39,006          33,215          5,791
  Gas (MMcf)                             601,907         583,583         18,324
  NGLs (MBbl)                              4,585           4,504             81
  MBoe (3)                               143,909         134,983          8,926
  Pre-tax Future Net Revenue             757,037         732,516         24,521
      ($ thousands) (4)
  Pre-tax 10% Present Value              462,921         451,142         11,779
      ($ thousands) (4)

<FN>
(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, 1998. 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 $9.89 per Bbl of oil,
  $1.70 per Mcf of natural gas and $7.25 per Bbl of NGLs. These
  prices compare to December 31, 1998, benchmark posted prices
  of $9.50 per Bbl for West Texas Intermediate crude oil and a
  composite of $2.02 per MMBtu for Texas Gulf Coast spot gas for
  gas delivered to various Texas Gulf Coast pipelines.
</TABLE>
     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, 1998. 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 NGL 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, 1998, 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, 1998:
<TABLE>
<CAPTION>
              Oil Wells            Gas Wells          Total Wells
           Gross(1)  Net(2)     Gross(1)  Net(2)    Gross(1)  Net(2)
           
    <S>     <C>       <C>        <C>     <C>         <C>      <C>
    U.S.     8,319    1,230      3,188     831       11,507   2,061
                                                  
    Canada   1,765      554      1,505     628        3,270   1,182
    
    Total   10,084    1,784      4,693   1,459       14,777   3,243
                                                 
<FN>
    (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.
</TABLE>
     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.


Undeveloped Acreage

     The following table sets forth Devon's developed and
undeveloped oil and gas lease and mineral acreage as of December
31, 1998.
<TABLE>
<CAPTION>
                       Developed           Undeveloped
                  Gross (1)   Net (2)   Gross (1)    Net (2)
                                       
United States                                     
     <S>          <C>         <C>      <C>         <C>
     Alabama              -         -      4,866     2,450
     Arkansas         5,909       589     14,699     3,770
     Colorado         1,919       452     23,962    10,237
     Kansas          20,498     8,372      6,839     1,055
     Louisiana        5,369       712        778       484
     Mississippi      3,784       828     16,331     6,626
     Montana          1,234       113     12,371     2,019
     Nebraska             -         -      6,517     1,377
     New Mexico     161,369    60,544    232,495    74,972
     North Dakota     7,467     2,455     13,573     3,778
     Oklahoma       198,855    70,330    290,758    70,506
     South Dakota     3,633        89        162        78
     Texas          736,245   208,576    657,189   206,230
     Utah             4,066       820      3,397     2,179
     Wyoming        174,323    88,552    304,490   222,681
     Total U.S.   1,324,671   442,432  1,588,427   608,442
</TABLE>
          

<TABLE>
<CAPTION>
                       Developed                 Undeveloped
                  Gross (1)   Net (2)       Gross (1)    Net (2)
                                     
Canada                                            
     <S>            <C>          <C>        <C>        <C>
     Alberta        1,103,813    577,327    2,607,601  1,907,675
     British            9,872      4,048      296,277    216,856
       Columbia
     Manitoba             -         -             399       399
     Saskatchewan       6,346      2,618       58,928    43,192
     Northwest                                            
     Territories          -         -         31,768      6,599
     Total Canada   1,120,031    583,993   2,994,982  2,174,721
                                                       
Grand Total         2,444,702  1,026,425   4,583,409  2,783,163
                                                      
<FN>
       (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.
</TABLE>

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 3,429 of its wells.  These
operated wells account for approximately 80% of Devon's total
proved reserves.  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, 1998.

<TABLE>
<CAPTION>
                                                                                10% Present
                                                                                 Value (3)    10% Present
                          Oil(MBbls)  Gas(MMcf)  NGLs(MBbl)  MBoe(1)  MBoe% (2)  ($000)        Value% (4)

United States
Permian Basin:
West Texas and
Southeast New Mexico
 <S>                       <C>     <C>          <C>         <C>       <C>       <C>           <C>
 Grayburg-Jackson Field    11,617       3,306       900      13,068     4.4%    $   5,728      0.6%
 Ozona Field                  235      53,080     3,104      12,185     4.1%       41,359      4.1%
 Other                     14,145      66,086     2,962      28,122     9.4%       88,823      8.8%
 Total                     25,997     122,472     6,966      53,375    17.9%      135,910     13.5%

Rocky Mountains:
Colorado and Wyoming
  House Creek Area         11,601         154        41      11,668     3.9%       29,532      2.9%
  Powder River Coalbed
      Methane Project           -      69,269         -      11,545     3.9%       38,094      3.8%
  Other                      5,399     73,914     2,511      20,228     6.8%       87,403      8.7%  
  Total                     17,000    143,337     2,552      43,441    14.6%      155,029     15.4%

San Juan Basin:
Northwest New Mexico
  Northeast Blanco Unit        314      1,491        99      23,685     7.9%      104,821(5)  10.4%
  32-9 Unit                      -     70,234         5      11,710     3.9%       47,336(6)   4.7%
  Other                          8        629        25         137      - %          426        -%
  Total                        112     12,354       129      35,532    11.8%      152,583     15.1%

Other U.S. Properties        1,443    118,824     1,847      23,095     7.7%      102,596     10.2%

Canada
Northern Alberta:
Northern Alberta and
Northern British Columbia
  Smoky Bear Area                -   113,920          8      18,995     6.3%       82,070      8.1%
  Other                     12,284   186,078        936      44,233    14.8%      153,788     15.2%
  Total                     12,284   299,998        944      63,228    21.1%      235,858(7)  23.3%

Southern Alberta:
Central and Southern
Alberta                     26,722   170,502      3,641      58,780    19.6%      175,878(7)  17.4%

Foothills:
Southwestern Alberta and
Eastern British Columbia
  Coleman Field                  -    91,259         -       15,210     5.1%       41,466      4.1%
  Other                          -    40,148         -        6,690     2.2%        9,719      1.0%
  Total                          -   131,407         -       21,900     7.3%       51,185(7)   5.1%


Grand Total                 83,457 1,198,894     16,079     299,351    100.0%   $1,009,039   100.0%

<FN>
(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) Percentage which present value for the basin or region bears
    to total present value for all Proved Reserves.
(5) Includes $15.8 million of additional value attributable to
    the San Juan Basin Transaction through the year 2002.
(6) Includes $10.3 million of additional value attributable to
    the San Juan Basin Transaction through the year 2002.
(7) Canadian dollars converted to U.S. dollars at the rate of $1
    Canadian: $0.6535 U.S.
</TABLE>
United States Properties

     Permian Basin Properties.  The Permian Basin is a prolific
oil and gas-producing region located in western Texas and
southeastern New Mexico. The area encompasses approximately
66,000 square miles and contains more than 500 major oil and gas
fields. Oil and gas leases within the Permian Basin are difficult
to obtain as much of the most prospective acreage is "held by
production" from existing wells or tied to large producing units.
Since 1987, Devon has made four significant acquisitions of
properties in the Permian Basin. These acquisitions have enabled
Devon to obtain prospective acreage in areas in which leasehold
positions could not otherwise be established. This large and well-
situated leasehold position continues to provide Devon with
numerous exploration and development opportunities. Devon has
also initiated enhanced oil recovery projects to further expand
reserves.  Devon's activity in the Permian Basin was limited in
1998 and will continue to be limited in 1999 due to low oil
prices.

     Grayburg-Jackson Field. Devon acquired the Grayburg-Jackson
Field in 1994. The property consists of approximately 8,600 acres
located in the southeastern New Mexico portion of the Permian
Basin. The field produces from an 800-foot thick interval of the
Grayburg and San Andres formations at depths between 3,000 and
4,000 feet. The Grayburg-Jackson Field contains approximately 14%
of Devon's proved oil reserves and is the Company's largest oil
property.

     Production in this field was first established in the
1930's.  However, most of the current producing wells were
drilled since 1970. When Devon acquired this property in 1994,
drilling by previous owners had developed the property on an
average spacing of over 40 acres per well. Additional oil
reserves were recovered from similar properties in the immediate
vicinity by infill drilling to 20 acres per well spacing and
subsequent waterflooding. Based upon analogy to these properties,
Devon initiated a $75 million capital development project in 1994
that included drilling approximately 184 infill wells, converting
selected producing wells to water injection wells and optimizing
the existing waterflood. Devon substantially completed the infill
drilling phase of the project in 1996. The majority of the field
was in the initial phases of water injection by mid-1997.
Completion of the waterflood facilities over the remainder of the
field will require the additional conversion of about 39
producing wells to injection wells.

     At year-end 1998, gross production averaged approximately
2,600 Boe per day. Devon anticipates that continued water
injection will further improve oil and gas recoveries.

     Ozona Field. The Ozona Field encompasses more than 200,000
acres in Crockett County, Texas, situated 120 miles southeast of
Midland, Texas. The field produces gas primarily from the Canyon
and Strawn formations at depths ranging from approximately 6,000
to 10,000 feet. The field has been developed on 80-acre spacing,
with portions now being infill drilled to 40-acre spacing.

     San Juan Basin.  Devon's single largest natural gas reserve
position relates to its interests in two federal units in the
northwest New Mexico portion of the San Juan Basin: the 33,000
acre Northeast Blanco Unit ("NEBU"), in Rio Arriba and San Juan
Counties, and the 22,400 acre 32-9 Unit in San Juan County. The
San Juan Basin is a densely drilled area covering 3,700 square
miles in central and northwestern New Mexico.  It has been
historically considered the second largest gas producing basin in
the United States.  Prior to 1990, the Basin's gas production
primarily came from conventional sandstone formations at a depth
of about 5,500 feet. However, in the early 1980's, development of
the shallower Fruitland coal formation began.  Coal seam gas
production has increased total production so significantly that
the San Juan Basin could be considered the largest gas producing
basin in the U.S.  Production from the coal seams constitutes
almost all of Devon's reserves in these two units.

     Substantially all of Devon's interests in both of these
units are a part of a transaction into which the Company entered
effective January 1, 1995.  See " - San Juan Basin Transaction"
below.

     Northeast Blanco Unit.  Approximately 96%, or 135 Bcf, of
Devon's proved reserves attributable to NEBU are associated with
the Fruitland Coal formation. The potential for gas production
from coal seams varies depending upon the thickness of the coal
formation, the type of coal in place, the depth at which it is
found and other factors.  NEBU is located in the central part of
the San Juan Basin where each of the factors is at or near its
optimum.  NEBU is operated by Devon. The Company initially began
developing its coal seam interest during 1988, eventually
drilling 102 wells -- the maximum permitted under existing
320-acre spacing on NEBU's 33,000 acres.

     In the near term, Devon is implementing various projects
that have already increased and may continue to increase
production and recoverable reserves. The first of these projects,
called "line looping," involves laying additional gathering lines
to decrease operating pressures. This project was begun in 1996
and was substantially completed in October 1997. Another project
involves the installation of additional compressors at various
points in the gathering system and at central delivery points
associated with NEBU.  This project was begun in 1997 and will
continue in 1999.  Additional projects to improve production
through work on individual wells are currently underway.  Longer
term, Devon believes that additional wells may be drilled which
could improve production.

     Initial results from the line looping and compression
projects that have been completed through March 1999, appear
favorable.  Total daily production from NEBU has increased from
an average of 187 MMcf of gas per day in June 1996 to an average
of 243 MMcf of gas per day in March 1999.  Devon anticipates that
the installation of additional compression and individual well
workovers could increase production from NEBU another 10 MMcf to
15 MMcf of gas per day.

     As part of the San Juan Basin Transaction (discussed in more
detail below), a third party will pay 100% of Devon's share of
the capital necessary to increase production from the existing
NEBU wells. Devon is entitled to retain 75% of any reserves in
excess of those estimated to be in place at the time of the
transaction which are developed as a result of such capital
expenditures. See " - San Juan Basin Transaction" below.

     32-9 Unit.  The 32-9 Unit is located approximately eight
miles northwest of NEBU. Geologically and operationally this
property is very similar to NEBU; the coal seams at the 32-9 Unit
are about the same thickness as at NEBU, the type of coal and the
depth at which it is found are similar and the gas content of the
coal is estimated to be approximately the same. However, the 32-9
Unit is located in an area where the coal does not appear to be
as permeable as it is at NEBU. Thus, the 32-9 Unit wells tend to
produce at lower rates but should produce for a longer period of
time than the NEBU wells. Longer term, Devon believes that
additional wells may be drilled which could improve production.
This unit is also being evaluated for possible mechanical
improvements similar to those being implemented at NEBU.

     San Juan Basin Transaction.  Effective January 1, 1995,
Devon and an unrelated company entered into a transaction
covering substantially all of Devon's San Juan Basin coal seam
properties. The effect of the transaction is that the price Devon
receives for its coal seam gas production ranges between $0.40
and $0.60 per Mcf (subject to adjustment for inflation) higher
than the price the Company would otherwise receive during the
period from 1995 through the year 2002. For a detailed discussion
of this transaction, see note 3 to Devon's consolidated financial
statements included elsewhere herein.

     Rocky Mountain Properties. The Rocky Mountain region
includes oil and gas producing basins that are grouped together
because of their geographic location rather than their geological
characteristics. The area generally encompasses all or portions
of the states of Colorado, Montana, New Mexico, North Dakota,
Utah and Wyoming. Devon's properties are primarily located in the
Big Horn and Powder River Basins in Wyoming.

     House Creek Area. The House Creek area is located in
Campbell County, Wyoming within the prolific Powder River Basin.
Devon acquired its original interest in the area at year-end
1996.  In 1997, the Company purchased additional interests.  The
area, which produces oil from the Sussex Sandstone reservoir at
depths of 8,200 feet, covers an area thirty miles long and two
miles wide.  The Area is divided into two production units.
Devon operates the southern two-thirds of the area, designated as
the House Creek Sussex Unit, with a 46% working interest. An
infill drilling program was initiated late in 1997 which resulted
in the addition of 75 producing and injector wells. These new
locations have effectively reduced well spacing from 160 to 80
acres per well in most of the area. A third party operates the
northern one-third of the area, designated as the House Creek
North Sussex Unit.  Devon has a 26% working interest in the North
Unit.  Additional infill drilling is also underway in the North
Unit.  Both portions of the area are currently under waterflood.
Total daily gross production from House Creek has increased from
an average of 4,600 Boe per day at year-end 1997 to an average of
5,700 Boe per day in January 1999.

     Powder River Coalbed Methane Project.  Devon has had a small
interest in the Powder River Basin in Campbell County, Wyoming
since the early 1980's.  The Company added to its position in
1992 with the acquisition of a small group of producing
properties and undeveloped leasehold.  An acquisition in 1996
added significantly to reserves and undeveloped lease inventory.
Virtually all of the production and reserves from these
acquisitions was oil.  However, a significant portion of the
acreage included relatively shallow (approximately 600 to 1,000
feet deep) coal seams containing methane. This gas had not been
developed due to relatively small gas reserves per well, the lack
of low-pressure gas pipelines to collect the gas and insufficient
pipeline capacity out of the region to deliver the gas to market.

     However, since the mid-1990's industry participants have
attained commercial production from coal wells by using
inexpensive drilling techniques.  Based on this information,
Devon began to formulate a plan to develop the coal seam gas
potential.  The plan included significantly increasing the
Company's acreage position, drilling a large number of coalbed
methane wells to attain "critical mass" and constructing a gas
gathering system and related carbon dioxide removal facilities to
deliver the gas to any of several interstate pipelines.

     During 1998 Devon began to implement this plan by acquiring
significant interests in both producing coalbed methane wells and
undeveloped acreage.  In addition, Devon drilled 86 new coalbed
methane wells.  By year-end 1998, the Company had an interest in
216,000 net acres and 202 coalbed methane wells. In addition,
Devon has, together with a joint-venture partner, begun
construction of a 126-mile gas gathering system.  The gas
gathering system is expected to begin initial operations by the
fourth quarter of 1999. When it is fully developed, in 2001, this
system will have an estimated capacity of 450 MMcf of gas per day
and access to multiple interstate pipelines. It will provide
adequate capacity to transport not only Devon's natural gas
production, but also third party gas.

     Devon's total capital investment to the project is expected
to be approximately $50 million for drilling 750 net wells over
the next ten years and $50 to $150 million over the next three
years for the development of the gathering system and facilities.

     Canadian Properties

     All of Devon's Canadian properties are located within the
Western Canada Sedimentary Basin.  The Western Canada Sedimentary
Basin is a large geologic feature encompassing portions of
British Columbia, Alberta, Saskatchewan and Manitoba.  This 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.

     Northern Alberta Properties.  This area covers northern
Alberta and a portion of northeastern British Columbia.  The
Northern Alberta properties are primarily gas producing
properties, although both gas and oil is present in multiple
formations at varying depths.  A large portion of this region is
thick bog that can be accessed by heavy equipment only when the
ground is frozen ("winter-only access").  Therefore drilling and
workover activity must be carefully planned to occur within the
winter months, typically from mid-December through mid-March.

     Smoky Bear Area. Devon acquired an approximate 70% interest
in 196 producing wells and nearly 1.1 million net undeveloped
acres in this area of north-central Alberta through the Northstar
Combination.  The Smoky Bear Area consists of 16 separate fields
that produce gas from various shallow formations ranging from
1,000 to 2,500 feet. In addition, the Company owns an interest in
several gas processing facilities.  This was an active area for
drilling in 1998, during which Northstar drilled 101 gas wells,
including 72 completed wells.  After the Northstar Combination,
the Company completed an acquisition in late 1998 which added new
gas reserves and more than 400 additional gas wells.  Devon
expects to drill an additional 80 to 90 gas wells during 1999.
Due to Devon's large acreage position in this area, Smoky Bear is
expected to be the source for development and low-risk
exploratory drilling for several years.

     Southern Alberta Properties. This area covers central and
southern Alberta and a small portion of Saskatchewan. The
Company's position consists of an average 40% interest in 112
producing properties and 500,000 net undeveloped acres.  Existing
production is primarily from oil-producing formations ranging
from 2,300 to 13,200 feet.   Activity in this area was limited in
1998 and will continue to be limited in 1999 due to low oil
prices.  However, the undeveloped acreage offers the Company a
variety of oil and gas exploration and development opportunities
to pursue in the future.  This area is accessible year round.

     Foothills Properties.  This area spans the western edge of
the Western Canada Sedimentary Basin from southeast British
Columbia/southwest Alberta to northeast British Columbia along
the eastern slope of the Rocky Mountains.  It contains Devon's
largest Canadian producing property as well as a large
undeveloped acreage position.  Exploration in the Foothills is
typically oriented toward long-life natural gas reserves.
Although the risks and capital expenditures for this type of
exploration projects are high, the potential prospect sizes
ranges from 100 to 1,000 Bcf.

     Coleman Field.  The Coleman Field, located in the southern
portion of the Foothills, is Devon's largest Canadian property,
producing gas from multiple formations between 9,500 and 11,500
feet.  Northstar originally acquired an interest in the Coleman
sour gas processing plant and pipeline in 1993.  Through a merger
in 1997 this ownership increased to 100%.  Northstar then built a
reserve base consisting of 6 producing wells through acquisitions
and exploratory and development drilling.  During 1998 Northstar
drilled three exploratory wells in the Coleman Field, two of
which were productive.  During 1999 the Company will drill one
additional exploratory well and connect the two 1998 discoveries
to pipeline.


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

     Devon is involved in various routine legal proceedings
incidental to its business. However, to Devon's knowledge as of
March 22, 1999, there were no 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

     A special meeting of Devon's shareholders was held on
December 9, 1998.  The purpose of the meeting was to consider and
vote upon three issues:  (i) approval of the Combination
Agreement dated as of June 29, 1998 between the Company and
Northstar ("Proposal One"); (ii) approval of an amendment to
Devon's Certificate of Incorporation to authorize a class of
Special Voting Stock consisting of one share ("Proposal Two");
and (iii) approve an amendment to Devon's 1997 Stock Option Plan
to increase the number of shares available for grant under the
plan from two million to three million shares ("Proposal Three").

     Out of a total of 32,319,894 shares of common stock
outstanding and entitled to vote, 29,383,878 shares, or 93%, were
represented at the meeting in person or by proxy.  Each of the
proposals being voted upon was approved.  The voting results were
as follows:
<TABLE>
<CAPTION>
                 Proposal One    Proposal Two   Proposal Three
               
<S>              <C>             <C>             <C>
FOR:             27,711,778      27,690,644      28,236,615
AGAINST:             14,090          34,974       1,131,002
ABSTAIN:             45,420          45,670          16,261
WITHHELD:         1,612,590       1,612,590              na
               
</TABLE>
               
                              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.
<TABLE>
<CAPTION>
                                 American Stock Exchange     Toronto Stock Exchange
                                 High     Low      Daily       High    Low    Daily
                                 (US$)    (US$)   Volume       (CN$)   (CN$) Volume
1997:                                                                
<S>                              <C>      <C>    <C>           <C>      <C>   <C>
Quarter Ended March 31, 1997     38-7/8   29-1/2  64,500                  
Quarter Ended June 30, 1997      38-1/2   27-3/8  76,600
Quarter Ended September 30, 1997 45-1/4   36-1/8  54,200
Quarter Ended December 31, 1997  49-1/8   35      63,100                   
1998:
Quarter Ended March 31, 1998     41-1/8   32-7/8  90,867
Quarter Ended June 30, 1998      40-1/2   32-5/8  97,527                   
Quarter Ended September 30, 1998 36-5/8   26-1/8 158,909                   
Quarter Ended December 31, 1998* 36-11/16 27-3/4 140,888       45.45    42.75 13,961
1999:                                       
Quarter Ended March 31, 1999     31-3/4   20-1/8 152,341       48.00    30.40  4,208
(through March 22, 1999)                                
                                                                   
*  Trading of the exchangeable shares on the TSE commenced on
   December 15, 1998.
</TABLE>

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 24, 1999, there were 840 holders of record of Devon
common stock and 34 holders of record for the exchangeable
shares.

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."  Prior year amounts have been restated to combine
Devon and Northstar pursuant to the pooling-of-interests method of
accounting for business combinations.  Note 2 to the consolidated
financial statements included in Item 8 of this report contains
information on the 1998 combination of Devon and Northstar as well as
unaudited pro forma financial data for the years 1998, 1997 and 1996
pertaining to certain acquisitions during such periods.
<TABLE>
<CAPTION>
                                                           Year Ended December 31,
                                              1998       1997       1996       1995        1994                                    
                                                  (Thousands, Except Per Share Data and Ratios)
OPERATING RESULTS
  <S>                                       <C>         <C>        <C>        <C>         <C>
  Oil sales                                 $143,624    207,725    136,023    115,606     92,352
  Gas sales                                  209,344    219,459    101,443     71,194     74,048
  NGLs sales                                  16,692     24,920     19,299      9,091      7,195

  Other revenue                               17,848     47,555     34,570     14,252     13,953

  Total revenues                             387,508    499,659    291,335    210,143    187,548

  Lease operating expenses                   113,484    100,897     58,734     51,724     43,647
  Production taxes                            13,916     19,227     10,880      7,052      7,217
  Depreciation, depletion and amortization   123,844    169,108     70,307     73,440     67,392
  General and administrative expenses         23,554     24,381     15,111     14,906     13,908
  Northstar Combination expenses              13,149          -          -          -          -
  Interest expense                            22,632     18,788     12,662     10,885      6,384
  Deferred effect of changes in foreign
    currency exchange rate on subsidiary's 
    long-term debt                            16,104      5,860       199         307          -
  Distributions on preferred securities of
    subsidiary trust                           9,717      9,717     4,753           -          -

  Reduction of carrying value of oil and
    gas properties                           126,900    625,514         -      97,061     21,679

  Total costs and expenses                   463,300    973,492   172,646     255,375    160,227

  Earnings (loss) before income taxes        (75,792)  (473,833)  118,689     (45,232)    27,321
  Income tax expense (benefit):
    Current                                    7,687     26,857     7,834       5,292        956
    Deferred                                 (23,194)  (200,699)   43,252     (24,631)     9,440

    Total                                    (15,507)  (173,842)   51,086     (19,339)    10,396

  Net earnings (loss)                       $(60,285)  (299,991)   67,603     (25,893)    16,925

  Net earnings (loss) per share:
    Basic                                    $ (1.25)     (6.38)     2.06       (0.80)      0.54
    Diluted                                  $ (1.25)     (6.38)     1.99       (0.80)      0.54

<FN>
  Cash dividends per common share1           $  0.15       0.14      0.15        0.14       0.13
  Weighted average common shares
    outstanding - basic                       48,376     47,040    32,812      32,473     31,114
<FN>
  Ratio of earnings to fixed charges2            N/A        N/A      7.59         N/A       5.09
<CAPTION>
                                                                    December 31,
                                             1998       1997      1996         1995        1994
                                                                    (Thousands)
BALANCE SHEET DATA
Total assets                              $1,226,356  1,248,986 1,183,290     715,510    631,953
Long-term debt                            $  405,271    305,337    83,000     220,137    106,764
Convertible preferred securities of
     subsidiary trust                     $  149,500    149,500   149,500           -          -
Stockholders' equity                      $  522,963    596,546   678,772     394,647    410,916
<CAPTION>
                                                         Year Ended December 31,
                                              1998       1997       1996       1995       1994
                                                     (Thousands, Except Per Unit Data)
CASH FLOW DATA
  Net cash provided by operating 
    activities                            $  191,571    253,056   144,248     122,136    118,719
  Net cash used by investing activities   $ (271,960)  (147,583) (243,451)   (251,571)  (188,066)
  Net cash provided (used) by financing
    activities                            $   57,618    (77,141)   96,420     125,312     70,378
<FN>
  Modified EBITDA 3,5                     $  223,405    355,154   206,610     136,461    255,682
<FN>
  Cash margin 4,5                         $  183,369    299,792   181,361     120,284    115,436

PRODUCTION, PRICE AND OTHER DATA
  Production:
    Oil (MBbls)                               11,903     11,783     6,780       7,130      6,501
    Gas (MMcf)                               133,065    121,810    62,186      58,234     51,409
    NGLs (MBbls)                               1,939      1,891     1,255         831        720
<FN>
    MBoe 6                                    36,020     33,976    18,399      17,666     15,789
  Average prices:
    Oil (Per Bbl)                            $ 12.07      17.63     20.06       16.21      14.21
    Gas (Per Mcf)                            $  1.57       1.80      1.63        1.22       1.44
    NGLs (Per Bbl)                           $  8.61      13.18     15.38       10.94       9.99
<FN>
    Per Boe 6                                $ 10.26      13.31     13.96        11.09     10.99
  Costs per Boe:
    Operating costs                          $  3.54       3.54      3.78         3.33      3.22
    Depreciation, depletion and amortization
      of oil and gas properties              $  3.32       4.86      3.69         4.04      4.13
    General and administrative expenses      $  0.65       0.72      0.82         0.84      0.88

<FN>
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, 1995 and 1994
  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 are not representative of the actual amounts paid by Devon on
  an historical basis.  For the years 1998, 1997, 1996, 1995 and 1994,
  Devon's historical cash dividends per share were $0.20, $0.20, $0.14,
  $0.12 and $0.12, respectively.

<FN>
2 For purposes of calculating the ratio of earnings to fixed
  charges, (i) earnings consist of earnings before income taxes,
  plus fixed charges; and (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 the portion of rental expense
  estimated to be attributable to interest.  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.

<FN>
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.

<FN>
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.

<FN>
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 and because it is a
  component of Devon's and Northstar's debt covenants.  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.

<FN>
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.
</TABLE>
<PAGE>

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 1996 through 1998. Reference  is  made  to
"Item   6.  Selected  Financial  Data"  and  "Item  8.  Financial
Statements and Supplementary Data."

Overview

     On June 29, 1998, Devon and Northstar Energy Corporation
("Northstar") announced their intent to merge.  The combination
of the two companies (the "Northstar Combination") was closed on
December 10, 1998.  As a result of this transaction, Devon issued
the equivalent of 16.1 million common shares and assumed $307
million of long-term debt.  The Northstar Combination increased
Devon's proved oil and gas reserves by 115 million Boe, or 62%,
and its undeveloped acreage by 1.8 million acres, or 193%.

     The merger with Northstar was the largest transaction in
Devon's history.  All of Northstar's operations are located in
Canada, principally in the province of Alberta.  The Northstar
Combination established critical mass for Devon in Canada.  Devon
believes that it now has the sufficient size to enjoy a fuller
range of opportunities of doing business in Canada.

     The Northstar Combination significantly expanded Devon's
operations.  However, another significant contributing factor to
Devon's growth over the last three years was Devon's December 31,
1996, acquisition of all of Kerr-McGee Corporations's North
American onshore oil and gas exploration and production business
and properties (the "KMG-NAOS Properties").  Devon acquired the
KMG-NAOS Properties in exchange for approximately 10 million
shares of Devon common stock.  At that time, this transaction
increased Devon's proved reserves by 62 million Boe, or 50%.

     Devon's drilling and development efforts have also helped
fuel Devon's growth over the last three years.  Excluding
Northstar, Devon has spent approximately $309 million in its
exploration and development efforts from 1996 through 1998.
These costs included drilling 851 wells, of which 828 were
completed as producers.

     The Northstar Combination was accounted for under the
pooling-of-interests method of accounting for business
combinations.  Accordingly, Devon's prior years' results have
been restated to combine such results with those of Northstar for
all years presented.    Thus, the three-year comparisons of
various production, revenue and expense items presented later in
this section are shown as if Devon and Northstar had been
combined for all such periods.  Although this is consistent with
the financial presentation of the Northstar Combination, it
disguises the substantial changes in Devon's operations that have
occurred as a result of the Northstar Combination.

     To present the effects that the Northstar Combination, the
KMG-NAOS Properties acquisition and drilling and development
efforts have had on Devon's operations during the last three
years, the following statistics have been developed.  This data
assumes that the Northstar Combination was closed at the
beginning of 1998, but that prior year results were not restated.
Thus, it compares Devon's 1998 results, including Northstar, to
those of 1996 for Devon only, without Northstar.  Such comparison
yields the following fluctuations:

          Combined oil, gas and NGLs production increased 25.3
            million Boe, or 236%.
          Despite a 32% decrease in the combined average price of
            oil, gas and NGLs, total revenues increased $223.5
            million, or 136%.
          Net cash provided by operating activities increased
            $104.8 million, or 121%.  Cash margin increased $87.4
            million, or 91%.
          Net earnings dropped from $34.8 million in 1996 to a
            net loss of $60.3 million in 1998.  However, 1998's net
            loss included approximately $108.5 million of after-tax
            charges from a full cost ceiling writedown, non-cash
            foreign currency charges and merger costs.  Excluding
            these charges, 1998's net earnings as compared to 1996
            would have increased $13.4 million, or 39%.
          Operating expenses per Boe of production decreased
            $0.40 per Boe, or 10%.
          Depreciation, depletion and amortization of oil and gas
            properties per Boe decreased $0.56 per Boe, or 14%.
          General and administrative expenses per Boe decreased
            $0.20 per Boe, or 24%.

     During 1998, Devon marked its tenth anniversary as a public
company.  While Devon has consistently increased production over
this ten-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
decrease.  Thus, an oil and gas production company depletes part
of its asset base with each unit of oil and gas it produces.
Historically, Devon has been able to overcome this natural
decline by adding more reserves through drilling and acquisitions
than it produces.  However, 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
which are outside of its control, Devon's management has focused
its efforts on increasing oil and gas reserves and production and
on controlling expenses.  Over its ten year history as a public
company, Devon has been able to significantly reduce its
operating costs per unit of production.  While Devon's per-unit
operating costs had been increasing since 1994, the Northstar
Combination reduced 1998's per-unit operating costs on a
consolidated basis by approximately $0.65 per Boe.  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.  This is
especially important considering the current depressed market for
oil and gas prices.

Results of Operations

     Devon's total revenues have risen from $291.3 million in
1996 to $499.7 million in 1997 and $387.5 million in 1998.  In
each of these years, oil, gas and NGLs sales accounted for over
88% of total revenues.

     Changes in oil, gas and NGLs production, prices and revenues
from 1996 to 1998 are shown in the table below.  (Unless
otherwise stated, all references in this discussion to dollar
amounts regarding Devon's Canadian operations are expressed in
U.S. dollars.)
<TABLE>
<CAPTION>
                                                Total
                                       Year Ended December 31,
                                        1998               1997
                               1998   vs 1997    1997    vs 1996   1996
                                   (Absolute Amounts in Thousands)
Production
  <S>                         <C>       <C>     <C>       <C>      <C>
  Oil (MBbls)                 11,903    +1%     11,783    +74%     6,780
  Gas (MMcf)                 133,065    +9%    121,810    +96%    62,186
  NGLs (MBbls)                 1,939    +3%      1,891    +51%     1,255
  Oil, Gas and NGLs (MBoe)    36,020    +6%     33,976    +85%    18,399

Revenues
  Per Unit of Production:
     Oil (per Bbl)           $ 12.07   -32%      17.63    -12%     20.06
     Gas (per Mcf)           $  1.57   -13%       1.80    +10%      1.63
     NGLs (per Bbl)          $  8.61   -35%      13.18    -14%     15.38
     Oil, Gas and NGLs 
       (per Boe)             $ 10.26   -23%      13.31     -5%     13.96

  Absolute:
    Oil                    $ 143,624   -31%    207,725   +53%   136,023
    Gas                    $ 209,344    -5%    219,459  +116%   101,443
    NGLs                   $  16,692   -33%     24,920   +29%    19,299
    Oil, Gas and NGLs      $ 369,660   -18%    452,104   +76%   256,765
<CAPTION>
                                               Domestic
                                       Year Ended December 31,
                                       1998               1997
                               1998  vs 1997     1997   vs 1996   1996
                                   (Absolute Amounts in Thousands)
Production
  Oil (MBbls)                  5,646    -7%      6,055    +59%    3,816
  Gas (MMcf)                  65,907    +8%     61,015    +71%   35,714
  NGLs (MBbls)                 1,373    -6%      1,468    +54%      952
  Oil, Gas and NGLs (MBoe)    18,004    +2%     17,692    +65%   10,720

Revenues
  Per Unit of Production:
     Oil (per Bbl)           $ 12.45   -35%      19.08     -9%    21.00
     Gas (per Mcf)           $  1.92   -16%       2.28    +19%     1.91
     NGLs (per Bbl)          $  8.79   -33%      13.18    -13%    15.09
     Oil, Gas and NGLs
      (per Boe)              $ 11.59   -25%      15.48     +2%    15.16

  Absolute:
    Oil                    $  70,286   -39%    115,504    +44%   80,142
    Gas                    $ 126,273    -9%    139,018   +104%   68,049
    NGLs                   $  12,071   -38%     19,338    +35%   14,367
    Oil, Gas and NGLs      $ 208,630   -24%    273,860    +68%  162,558
<CAPTION>
                                               Canada
                                       Year Ended December 31,
                                       1998               1997
                               1998  vs 1997    1997    vs 1996  1996
                                  (Absolute Amounts in Thousands)

Production
  Oil (MBbls)                  6,257   +9%      5,728     +93%   2,964
  Gas (MMcf)                  67,158  +10%     60,795    +130%  26,472
  NGLs (MBbls)                   566  +34%        423     +40%     303
  Oil, Gas and NGLs (MBoe)    18,016  +11%     16,284    +112%   7,679

Revenues
  Per Unit of Production:
     Oil (per Bbl)           $ 11.72  -27%      16.10    -15%    18.85
     Gas (per Mcf)           $  1.24   -6%       1.32     +5%     1.26
     NGLs (per Bbl)          $  8.16  -38%      13.20    -19%    16.28
     Oil, Gas and NGLs 
      (per Boe)              $  8.94  -18%      10.95    -11%    12.27

  Absolute:
    Oil                    $  73,338  -20%     92,221    +65%   55,881
    Gas                    $  83,071   +3%     80,441   +141%   33,394
    NGLs                   $   4,621  -17%      5,582    +13%    4,932
    Oil, Gas and NGLs      $ 161,030  -10%    178,244    +89%   94,207
</TABLE>

     Oil Revenues  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.

     1997 vs. 1996  Oil revenues increased $71.7 million in 1997.
Production gains of 5.0 million barrels added $100.4 million of
oil revenues in 1997.  This increase was partially offset by a
$28.7 million reduction in oil revenues due to price declines in
1997.  The average oil price decreased $2.43 per barrel in 1997.

     In March 1997, Northstar acquired all the outstanding common
shares of Morrison Petroleums Ltd., an independent oil and gas
producer also located in Alberta, Canada.  Northstar acquired the
Morrison Petroleums Ltd. shares by issuing additional shares of
Northstar (the "Morrison Transaction").  The March 1997 Morrison
Transaction and the KMG-NAOS Properties acquired at the end of
1996 were the primary contributors to the increased oil
production in 1997.  The KMG-NAOS Properties added 3.1 million
barrels of 1997 production.  The Morrison Transaction added 2.7
million barrels during the last nine months of 1997.

     Gas Revenues  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 coal seam gas properties produced 19.9 Bcf in 1998
compared to 17.6 Bcf in 1997. During the last two years, Devon
has conducted a program of mechanical improvements at the
Northeast Blanco Unit coal seam gas property.  The majority of
the production gains realized in 1998 were the result of such
improvements.

     The coal seam properties averaged $1.72 per Mcf in 1998
compared to $2.13 per Mcf in 1997.  In 1995, Devon entered into a
transaction covering substantially all of its San Juan Basin coal
seam gas properties (the "San Juan Basin Transaction").  This
transaction is described in detail in Note 3 to the consolidated
financial statements uncluded in "Item 8. Financial Statements
and Supplementary Data".  The San Juan Basin Transaction added
$8.4 million to coal seam gas revenues in both 1998 and 1997.
The San Juan Basin Transaction's effect on the coal seam gas
properties' average price was an increase of $0.42 per Mcf in
1998 and $0.48 per Mcf in 1997.

     1997 vs. 1996  Gas revenues increased $118.0 million in
1997.  A 59.6 Bcf increase in production added $97.3 million to
1997's gas revenues.  A $0.17 per Mcf increase in 1997's average
gas price added the remaining $20.7 million of increased
revenues.

     The KMG-NAOS Properties and the Morrison Transaction were
responsible for the majority of the increased gas production in
1997.  The KMG-NAOS Properties produced 29.8 Bcf in 1997.  The
Morrison Transaction added 26.4 Bcf in the last nine months of
the year.  Coal seam gas properties produced 17.6 Bcf in 1997
compared to 17.4 Bcf in 1996.

     The coal seam properties averaged $2.13 per Mcf in 1997
compared to $1.72 per Mcf in 1996.  The San Juan Basin
Transaction added $8.4 million to coal seam gas revenues in 1997
compared to $10.3 million in 1996.  The San Juan Basin
Transaction increased the average coal seam gas price by $0.48
per Mcf in 1997 and $0.59 per Mcf in 1996.

     NGLs Revenues  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 only
slightly offset by production increases of 48,000 barrels.  Such
production gains added $0.7 million of revenues in 1998.

     1997 vs. 1996  NGLs revenues increased $5.6 million in 1997.
A production increase of 636,000 barrels added $9.8 million to
1997's revenues.  This was partially offset by a $4.2 million
reduction in revenues caused by lower prices in 1997.  The
average NGLs price dropped $2.20 per barrel in 1997.

     The majority of the increased production in 1997 was
attributable to the KMG-NAOS Properties and the Morrison
Transaction.  The KMG-NAOS Properties added 339,000 barrels to
1997's production.  The Morrison Transaction added 161,000
barrels during the last nine months of 1997.

     Other Revenues  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.

     1997 vs. 1996  Other revenues increased $13.0 million in
1997.  Northstar's gains from sales of assets increased $18.8
million in 1997.  Northstar's pipeline revenues decreased $3.5
million and its equity earnings from unconsolidated subsidiaries
decreased $3.2 million in 1997.

     Expenses  The details of the changes in pre-tax expenses
between 1996 and 1998 are shown in the table below.
<TABLE>
<CAPTION>
                                                         Year Ended December 31,
                                                      1998                   1997
                                            1998    vs 1997      1997      vs 1996      1996
                                                   (Absolute Amounts in Thousands)
Absolute:
  Production and operating expenses:
    <S>                                 <C>           <C>       <C>         <C>        <C>
    Lease operating expenses            $ 113,484     +12%      100,897     +72%       58,734
    Production taxes                       13,916     -28%       19,227     +77%       10,880
  Depreciation, depletion and amortiza-
    tion of oil and gas properties        119,719     -27%      164,977    +143%       67,832

      Subtotal                            247,119     -13%      285,101    +107%      137,446
  Depreciation and amortization of 
    non-oil and gas properties              4,125       -         4,131     +67%        2,475
  General and administrative expenses      23,554      -3%       24,381     +61%       15,111
  Northstar Combination expenses           13,149     N/A             -     N/A             -
  Interest expense                         22,632     +20%       18,788     +48%       12,662
  Deferred effect of changes in foreign
    currency exchange rate on subsidiary's
    long-term debt                         16,104    +175%        5,860     N/A           199
  Distributions on preferred securities of
    subsidiary trust                        9,717       -         9,717    +104%        4,753
  Reduction of carrying value of oil and
    gas properties                        126,900     -80%      625,514     N/A             -

      Total                             $ 463,300     -52%      973,492    +464%      172,646

Per Boe Produced:
  Production and operating expenses:
     Lease operating expenses              $ 3.15      +6%         2.97      -7%         3.19
     Production  taxes                       0.39     -32%         0.57      -3%         0.59
  Depreciation, depletion and amortiza-
    tion of oil and gas properties           3.32     -32%         4.86     +32%         3.69

        Subtotal                             6.86     -18%         8.40     +12%         7.47

  Depreciation and amortization of 
<FN>
    non-oil and gas properties (1)           0.12       -          0.12      -8%         0.13
<FN>
  General and administrative expenses (1)    0.65     -10%         0.72     -12%         0.82
<FN>
  Northstar Combination expenses (1)         0.36     N/A             -     N/A             -
<FN>
  Interest expense (1)                       0.63     +15%         0.55     -20%         0.69
  Deferred effect of changes in foreign 
   currency exchange rate on subsidiary's
<FN>
   long-term debt (1)                        0.45    +165%         0.17     N/A          0.01
  Distributions on preferred securities of
<FN>
    subsidiary trust (1)                     0.27      -4%         0.28      +8%         0.26
  Reduction of carrying value of oil and gas
<FN>
    properties (1)                           3.52     -81%        18.41     N/A             -

      Total                               $ 12.86     -55%        28.65    +205%         9.38

<FN>
(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.
</TABLE>

        Production and Operating Expenses  The  details  of  the
changes  in  production and operating expenses between  1996  and
1998 are shown in the table below.
<TABLE>
<CAPTION>
                                                                       Total
                                                              Year Ended December 31,
                                                             1998                 1997
                                                 1998      vs 1997     1997     vs 1996     1996
                                                         (Absolute Amounts in Thousands)

Absolute:
  <S>                                         <C>            <C>      <C>        <C>       <C>
  Recurring lease operating expenses          $ 107,554      +11%     96,738     +79%      54,171
  Well workover expenses                          5,930      +43%      4,159      -9%       4,563
  Production taxes                               13,916      -28%     19,227     +77%      10,880

     Total production and operating expenses  $ 127,400       +6%    120,124     +73%      69,614

Per Boe:
  Recurring lease operating expenses             $ 2.99       +5%       2.85      -3%        2.94
  Well workover expenses                           0.16      +33%       0.12     -52%        0.25
  Production taxes                                 0.39      -32%       0.57      -3%        0.59

      Total production and operating expenses    $ 3.54        -        3.54      -6%        3.78

<CAPTION>
                                                                     Domestic
                                                              Year Ended December 31,
                                                             1998                 1997
                                                  1998     vs 1997     1997     vs 1996     1996
                                                          (Absolute Amounts in Thousands)

Absolute:
  Recurring lease operating expenses           $  60,920     +11%     54,969     +94%      28,270
  Well workover expenses                           4,654     +48%      3,143      -5%       3,298
  Production taxes                                12,255     -31%     17,646     +66%      10,658

     Total production and operating expenses   $  77,829      +3%     75,758     +79%      42,226

Per Boe:
  Recurring lease operating expenses              $ 3.38      +9%       3.10     +17%        2.64
  Well workover expenses                            0.26     +44%       0.18     -42%        0.31
  Production taxes                                  0.68     -32%       1.00      +1%        0.99

      Total production and operating expenses     $ 4.32      +1%       4.28      +9%        3.94

<CAPTION>
                                                                      Canada
                                                              Year Ended December 31,
                                                             1998                1997
                                                  1998     vs 1997     1997    vs 1996      1996
                                                           (Absolute Amounts in Thousands)

Absolute:
  Recurring lease operating expenses            $  46,634    +12%     41,769     +61%      25,901
  Well workover expenses                            1,276    +26%      1,016     -20%       1,265
  Production taxes                                  1,661     +5%      1,581    +612%         222

     Total production and operating expenses    $  49,571    +12%     44,366     +62%      27,388

Per Boe:
  Recurring lease operating expenses               $ 2.59     +1%       2.56     -24%        3.37
  Well workover expenses                             0.07    +17%       0.06     -65%        0.17
  Production taxes                                   0.09    -10%       0.10    +233%        0.03

     Total production and operating expenses       $ 2.75     +1%       2.72     -24%        3.57
</TABLE>

     1998 vs. 1997  Recurring lease operating expenses increased
$10.8 million, or 11%, in 1998.  The primary cause of this
increase was the addition of wells drilled or acquired during the
year, plus the effect of having a full year of operations from
the Morrison Transaction properties in 1998 compared to only nine
months in 1997.

     The recurring expenses per Boe increased $0.14 per Boe, or
5%, in 1998.  This increase was predominantly caused by the 9%
increase in the domestic properties' costs per Boe.  The
operating expenses of the additional domestic wells drilled
during the year raised the overall average costs per Boe in the
U.S.

     The majority of Devon's production taxes are assessed on its
domestic properties.  In the U.S., most of the production taxes
paid are based on a fixed percentage of revenues.  Therefore, the
24% drop in domestic oil, gas and NGLs revenues was the primary
cause of the 31% decrease in domestic production taxes.

     1997 vs. 1996  Recurring lease operating expenses increased
$42.6 million, or 79%, in 1997.  The KMG-NAOS Properties
accounted for $26.0 million of the increased expenses.  The
Morrison Transaction added $16.5 million during the last nine
months of 1997.

     Recurring expenses per Boe were down $0.09 per Boe, or 3%,
in 1997.  The addition of the properties acquired in the Morrison
Transaction accounted for the majority of this decrease in per
unit costs.  Such properties' costs per Boe for the last nine
months of 1997 were $2.28 per Boe.  This compares to $3.00 per
Boe for all other properties during the year 1997.

     Domestic production taxes increased 66% in 1997.  This
increase was mostly due to the 68% increase in the U.S. combined
oil, gas and NGLs revenues.

     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
capitalized costs change, 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 for the domestic and Canadian properties.

     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 domestic DD&A rate per Boe increased from $4.13 in 1997 to
$4.24 in 1998.  However, the Canadian DD&A rate per Boe decreased
from $5.64 in 1997 to $2.41 in 1998.  The $625.5 million
reduction in the carrying value of Canadian oil and gas
properties recorded at the end of 1997 caused the drop in the
Canadian DD&A rate in 1998.

     1997 vs. 1996  Oil and gas property related DD&A increased
$97.1 million, or 143%, in 1997.  Approximately $57.4 million of
the increase was caused by the 85% increase in combined oil, gas
and NGLs production in 1997.  The remaining $39.7 million was
caused by a 32% increase in the combined domestic and Canadian
DD&A rate.  The combined rate increased from $3.69 per Boe in
1996 to $4.86 per Boe in 1997.  The domestic rate increased from
$3.88 per Boe in 1996 to $4.13 per Boe in 1997.  The Canadian
rate increased from $3.42 per Boe in 1996 to $5.64 per Boe in
1997.  The increase in 1997's Canadian rate was caused by the
cost per Boe of the properties acquired in the Morrison
Transaction.

     General and Administrative Expenses ("G&A")  1998 vs. 1997
G&A decreased $0.8 million, or 3%, in 1998.  Employee salaries
and related overhead costs, including insurance and pension
expense, increased $3.0 million in 1998 due to a combination of
compensation increases and an increase in the number of personnel
employed.

     The higher salary and overhead costs were partially offset
by an increase in the amount of such costs that were capitalized
pursuant to the full cost method of accounting.  Approximately
$9.6 million of costs were capitalized in 1998, compared to $7.6
million in 1997.

     The higher salary and overhead costs were also partially
offset by an increase in Devon's overhead reimbursements.  As the
operator of a property, Devon receives these reimbursements from
the property's working interest owners.  Devon records the
reimbursements as reductions to G&A.  These reimbursements
increased $1.9 million in 1998.

     1997 vs. 1996  G&A increased $9.3 million, or 61% in 1997.
Employee salaries and related overhead costs, including insurance
and pension expense, increased $11.7 million.  This increase was
primarily related to the additional permanent and temporary
personnel added at Devon's Oklahoma City and Calgary offices as a
result of the acquisition of the KMG-NAOS Properties and the
Morrison Transaction.  The personnel expansion also caused office-
related costs such as rent, dues, travel, supplies, telephone,
etc., to increase $3.3 million in 1997.

     The higher salary, overhead and office costs were partially
offset by an increase in the amount of such costs that were
capitalized pursuant to the full cost method of accounting.
Approximately $7.6 million of costs were capitalized in 1997,
compared to $4.9 million capitalized in 1996.

     The higher salary, overhead and office costs were also
partially offset by an increase in Devon's overhead
reimbursements.  Due largely to the acquisition of the KMG-NAOS
Properties and the Morrison Transaction, overhead reimbursements
increased $4.4 million in 1997.

     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  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.

     1997 vs. 1996  Interest expense increased $6.1 million, or
48%, in 1997.  The average long-term debt balance increased from
$183.8 million in 1996 to $267.0 million in 1997.  This increase
in the average balance caused interest expense to increase $5.1
million.  The average interest rate decreased from 6.1% in 1996
to 5.4% in 1997.  This decrease reduced interest expense $2.0
million in 1997.  Interest expense in 1997 also included the $3.3
million make-whole payment discussed in the above paragraph.
Other items included in interest expense that are not related to
the balance of debt outstanding were $0.3 million lower in 1997
compared to 1996.

     Devon's average domestic long-term debt balance was almost
eliminated in 1997, as it dropped from an average of $77.0
million in 1996 to only $0.7 million in 1997.  Devon issued
$149.5 million of 6.5% Trust Convertible Preferred Securities
("TCP Securities") in July, 1996.  The proceeds from this
issuance, along with cash flow from operations, were used to
retire all domestic long-term debt by the end of the first
quarter of 1997.  (The TCP Securities are discussed further in
this section.)

     However, the drop in Devon's average domestic debt balance
was more than offset by an increase in the Canadian average
balance in 1997.  Following the Morrison Transaction, Northstar
repurchased $217 million of common shares which was financed with
long-term debt.  As a result, the Canadian average long-term debt
balance increased from $106.8 million in 1996 to $266.3 million
in 1997.

     Deferred Effect of Changes in Foreign Currency Exchange Rate
on Subsidiary's Long-term Debt  Northstar has certain fixed rate
senior notes which are denominated in U.S. dollars.  Changes in
the exchange rate between the U.S. dollar and the Canadian dollar
from the dates the notes were issued to the dates of repayment
will increase or decrease 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.
     
     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.
     
     1997 vs. 1996  The principal balance of Northstar's U.S.
dollar denominated notes increased from $75 million at the end of
1996 to $135 million at the end of 1997.  The rate of converting
Canadian dollars to U.S. dollars decreased from $0.7301 at the end
of 1996 to $0.6997 at the end of 1997.  The combination of these
factors caused $5.9 million to be recorded as an expense in 1997.
     
     Distributions on Preferred Securities of Subsidiary Trust
1998 vs. 1997  As mentioned earlier in this discussion, and 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%
TCP Securities in a private placement in July, 1996.  The
distributions accrue and are paid at the rate of 1.625% per
quarter.
     
     1997 vs. 1996  The TCP Securities distributions in 1997 were
$9.7 million compared to $4.8 million in 1996.  The 1996
distribution total represented slightly less than two quarters'
distributions due to the issuance date occurring in July of that
year.
     
     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.
     
     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  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.
     
     1997 vs. 1996  Devon's effective financial income tax
(benefit) rate in 1997 was (37%) compared to 43% in 1996.  The
benefit rate in 1997, as an absolute percentage, was lower than
1996's tax rate due to the financial deduction of costs in 1997
that were not deductible for income tax purposes.  As previously
discussed, Northstar recorded in 1997 a $625.5 million reduction
of carrying value of oil and gas properties.  Approximately $115.3
million of the reduction related to costs which are not deductible
for income tax purposes.  These non-deductible costs were the
primary cause of the low benefit rate in 1997.
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 $375.5 million was spent
in 1998 for capital expenditures, of which $371.3 million was
related to the acquisition, drilling or development of oil and gas
properties.  These amounts compare to 1997 total expenditures of
$288.0 million ($279.9 million of which was related to oil and gas
properties) and 1996 total expenditures of $268.7 million ($254.5
million of which was related to oil and gas properties.)
     
     Other Cash Uses  Devon's common stock dividends were $7.3
million, $6.4 million and $5.0 million in 1998, 1997 and 1996,
respectively.
     
     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 $191.6 million, $253.1 million and $144.2
million in 1998, 1997 and 1996, respectively.  The trends in
operating cash flow during these periods have generally followed
those of the various revenue and expense items previously
discussed in this section.
     
     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.  During the years 1998 and 1997,
long-term debt borrowings, net of repayments, totaled $55.3
million and $127.2 million, respectively.  In 1996, due to the
application of the TCP Securities' proceeds against outstanding
debt, repayments of debt exceeded borrowings by $47.9 million.
     
     Following the closing of the Northstar combination in
December 1998, Devon entered into new unsecured long-term credit
facilities aggregating $400 million (the "Credit Facilities").
The Credit Facilities include a U.S. facility of $205 million
(the "U.S. Facility") and a Canadian facility of $195 million
(the "Canadian Facility").  The Credit Facilities replaced
Devon's and Northstar's separate credit facilities that were in
place prior to the Northstar Combination.  Of the $180.3 million
borrowed against the Credit Facilities at December 31, 1998, $35
million was borrowed under the U.S. Facility and $145.3 million
was borrowed under the Canadian Facility.  Amounts borrowed under
the Credit Facilities bear interest at various fixed rate options
that Devon may elect for periods up to six months.  Such rates
are generally less than the prime rate.  Devon may also elect to
borrow at the prime rate.  The average interest rate on the
$180.3 million of debt outstanding at December 31, 1998, was
5.9%.  The Credit Facilities also provide for an annual facility
fee of $0.4 million that is payable quarterly.
     
     The $205 million U.S. Facility consists of a Tranche A
facility of $130 million and a Tranche B facility of $75 million.
The Tranche A facility matures on December 10, 2003.  Devon may
borrow funds under the Tranche B facility until December 10, 1999
(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 not more than 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.  All $35 million of
debt outstanding under the U.S. Facility at December 31, 1998,
was borrowed under the Tranche A facility.
     
     Devon may borrow funds under the $195 million Canadian
Facility until December 10, 1999 (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 not more than 90 days prior to the
end of the Canadian Facility Revolving Period. Debt borrowed
under the Canadian Facility matures five years and one day
following the end of the Canadian Facility Revolving Period.
     
     Year 2000 Status  Devon's company-wide Year 2000 Project
("the Project") is proceeding on schedule.  The Project is
addressing the Year 2000 issue caused by computer programs being
written utilizing two digits rather than four to define an
applicable year.  As a result, Devon's computer equipment,
software (all of which is externally developed), and devices with
embedded technology that are time sensitive may misinterpret the
actual date beginning on January 1, 2000.  This could result in a
system failure or miscalculations causing disruptions of
operations, including, but not limited to, a temporary inability
to process transactions.
     
     Devon has undertaken various initiatives intended to ensure
that its computer equipment and software will function properly
with respect to dates in the Year 2000 and thereafter.  In
planning and developing the Project, Devon has considered both
its information technology ("IT") and its non-IT systems.  The
term "computer equipment and software" includes systems that are
commonly thought of as IT systems, including accounting, data
processing, telephone systems, scanning equipment, and other
miscellaneous systems.  Those items not to be considered as IT
technology include alarm systems, fax machines, monitors for
field operations, or other miscellaneous systems.  Both IT and
non-IT systems may contain embedded technology, which complicates
Devon's Year 2000 identification, assessment, remediation, and
testing efforts.  Based upon its identification and assessment
efforts to date, Devon is in the process of replacing the
computer equipment and software it currently uses to become Year
2000 compliant.  In addition, in the ordinary course of replacing
computer equipment and software, Devon plans to obtain
replacements that are in compliance with year 2000.
     
     Devon has also mailed letters to its significant vendors and
service providers and has verbally communicated with many
strategic customers to determine the extent to which interfaces
with such entities are vulnerable to Year 2000 issues and whether
the products and services purchased from or by such entities are
year 2000 compliant.  Devon has received an overall favorable
response from such third parties and it is anticipated that their
significant Year 2000 issues will be addressed on a timely basis.
     
     With regard to IT and non-IT systems and communications with
third parties, Devon anticipates that the Project will be
completed by September 30, 1999.
     
     As noted above, Devon is in the process of replacing certain
computer equipment and software because of the Year 2000 issue.
Devon estimates that the total cost of such replacements will
approximate $0.5 million.  Substantially all of the personnel
being used on the Project are existing Devon employees.  Devon
does not separately track the time that its own employees spend
on the Project.  Therefore, the internal costs incurred on the
Project are not known.  Such costs would consist almost entirely
of the payroll costs associated with the time spent on the
Project.  Third party consulting costs of Devon's Year 2000
identification, assessment, remediation and testing efforts, as
well as currently anticipated costs to be incurred with respect
to Year 2000 issues of third parties, are expected to be
approximately $0.2 million.
     
     Devon has not yet begun a comprehensive analysis of the
operational problems and costs that would be reasonably likely to
result from the failure by Devon and significant third parties to
complete efforts necessary to achieve Year 2000 compliance on a
timely basis.  A contingency plan has not been developed for
dealing with the most reasonably likely worst case scenario, and
such scenario has not yet been clearly identified.  Devon plans
to complete such analysis and contingency planning by December
31, 1999.
     
     Devon presently 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.
     
1999 Estimates
     
     The forward-looking statements provided in this discussion
are based on management's examination of historical operating
trends, the December 31, 1998 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 Canadian 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 90%
of Devon's revenues are attributable to sales of these three
commodities.  Consequently, Devon's financial results and
resources are highly influenced by this price volatility.
     
     Estimates for Devon's future production of oil, natural gas
and 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 are
sufficiently significant as to have a material impact on the
overall financial results.  With respect to oil production, these
properties include the West Red Lake Field and the Grayburg-
Jackson Unit, both in southeast New Mexico, and the Gilby and
Halkirk areas in Alberta.  Devon's interest in NEBU and the 32-9
Unit, both in the San Juan Basin, and the Coleman and Hamburg
areas in Alberta can have a significant effect on overall gas
production.
     
     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 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 1999 will be substantially similar to those of 1998, unless
otherwise noted.  Given the general limitations expressed herein,
Devon's forward-looking statements for 1999 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
1998 exchange rate of $0.6535 U.S. dollar to $1.00 Canadian
dollar.  The actual 1999 exchange rate may vary materially from
the year-end 1998 rate used.  Such variations could have a
material effect on the following Canadian estimates.
     
     Oil Production  Devon expects its oil production in 1999 to
total between 8.8 million barrels and 10.3 million barrels.
Domestic production is expected to be between 4.6 million barrels
and 5.4 million barrels, and Canadian production is expected to
be between 4.2 million barrels and 4.9 million barrels.
     
     Oil Prices  Devon expects its 1999 net oil prices per barrel
will average between $0.25 to $0.55 above West Texas Intermediate
("WTI") posted prices for its domestic production.  Approximately
180,000 barrels of Canadian oil production in the first quarter
have been fixed at a price of approximately $17.80 per barrel.
For the remainder of 1999's Canadian oil production, Devon
expects to receive a price between $1.75 and $2.25 below WTI
posted prices.
     
     The above expected range of the Canadian differentials from
WTI prices, as well as the $17.80 per barrel fixed price for
180,000 barrels of first quarter production, include an estimated
$1.25 per barrel decrease resulting from foreign currency hedges.
These hedges, in which Devon will sell $60 million in 1999 at an
average Canadian-to-U.S. exchange rate of $0.726 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. prices.  The $1.25 per barrel
decrease is based on the assumption that the year-end 1998
Canadian-to-U.S. conversion rate of $0.6535 remains constant
during 1999.
     
     Gas Production  Devon expects its 1999 gas production to
total between 122 Bcf and 143 Bcf.  It is expected that San Juan
Basin coal seam gas production will be between 19 Bcf and 23 Bcf,
and all other domestic production will be between 41 Bcf and 47
Bcf.  Canadian production is expected to be between 62 Bcf and 73
Bcf.
     
     Gas Prices - Fixed  Through various fixed price contracts or
hedging instruments, Devon has fixed the price it will receive in
1999 on a portion of its natural gas production.  The table below
includes the 1999 volumes and the respective prices that have
been fixed.
<TABLE>
<CAPTION>
                              Volumes       Price Per
         Area                 (MMcf)           Mcf
     
     <S>                      <C>             <C>
     San Juan Basin           13,100          $1.82
     Rocky Mountains           7,600          $1.93
     Other U.S.                1,500          $2.05

     Total U.S.               22,200          $1.87

     Canada                   41,600          $1.33
</TABLE>

     The above price for the San Juan Basin gas includes
approximately $0.41 per Mcf from the San Juan Basin Transaction.
Also, the above San Juan Basin price is net of approximately
$0.63 per Mcf for transportation costs and quality adjustments.

     Gas Prices - Floating  For the gas production for which
prices have not been fixed, Devon expects its 1999 San Juan Basin
coal seam average price will be between $0.25 and $0.55 per Mcf
less than Texas Gulf Coast spot averages ("TGC").  This includes
the additional $0.41 per Mcf from the San Juan Basin Transaction
and the $0.63 per Mcf reduction for transportation and quality
adjustments, both referred to in the previous paragraph.  Devon's
other domestic production is expected to average $0.05 to $0.20
less than TGC, and the Canadian production is expected to average
$0.80 to $0.95 less than the New York Mercantile Exchange price
("NYMEX").
     
     NGLs Production  Devon expects its production of 1999 NGLs
to total between 1.7 million barrels and 2.0 million barrels.
Between 1.3 million barrels and 1.5 million barrels are expected
to be produced domestically, and between 0.4 million barrels and
0.5 million barrels are expected to be produced in Canada.
     
     Other Revenues  Devon's other revenues in 1999 are expected
to be between $6.0 million and $7.5 million.  Domestic other
revenues are expected to be $2.0 million to $2.5 million and
Canadian other revenues are expected to be $4.0 million to $5.0
million.  The majority of these other revenues are expected to be
produced from third party gas processing activities.
     
     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 or deletions
to Devon's property base, changes in production taxes, general
changes in the prices 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 1999.  Future prices could
also 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
1999's total production and operating costs will be between $116
million and $135 million.  The U.S. portion of such estimate is
between $73 million and $84 million, while the Canadian costs are
expected to total between $43 million and $51 million.
     
     Depreciation, Depletion and Amortization  The 1999 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 1999 compared to the costs
incurred for such efforts, and the revisions to Devon's year-end
1998 reserve estimates that will be made during 1999.
     
     Devon expects that its consolidated DD&A expense in 1999
will be between $122 million and $151 million.  The DD&A rates as
of the beginning of 1999 were $3.92 per Boe for domestic
properties and $3.19 per Boe for Canadian properties.  Assuming a
1999 domestic rate of between $4.15 per Boe and $4.40 per Boe,
1999 oil and gas property related DD&A expense is expected to be
between $66 million and $81 million for the U.S. properties.
Assuming a 1999 Canadian rate of between $3.40 per Boe and $3.65
per Boe, 1999 oil and gas property related DD&A expense is
expected to be between $51 million and $64 million for the
Canadian properties.
     
     Additionally, Devon expects its 1999 non-oil and gas
property related DD&A to total between $3.9 million and $4.5
million in the U.S. and between $1.0 million and $1.3 million in
Canada.
     
     General and Administrative Expenses  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 1999 is expected to
be between $22.5 million and $26.0 million.  Domestic G&A is
expected to be between $10.5 million and $12.0 million, and
Canadian G&A is expected to be between $12.0 million and $14.0
million.

     Interest Expense  Future interest rates and oil, natural gas
and NGLs prices have a significant effect on Devon's interest
expense.  The fixed-rate provisions on $225 million of existing
long-term debt removes the uncertainty of future interest rates
from some, but not all, of Devon's long-term debt.  Also, Devon
can only marginally influence the prices it will receive in 1999
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
1999 will be between $28 million and $32 million.  Domestic
interest expense is expected to be between $4 million and $5
million, and Canadian interest expense is expected to be between
$24 million and $27 million.

     Deferred Effect of Changes in Foreign Currency Exchange Rate
on Subsidiary's Long-term Debt  Assuming that there are no
changes during 1999 in the existing principal balance of
Northstar's $225 million of long-term debt which is denominated
in U.S. dollars, the only factor influencing the potential 1999
deferred effect is the foreign currency rate between the U.S.
dollar and the Canadian dollar.  For every $0.01 change in the
exchange rate from the year-end 1998 rate of $0.6535, Northstar
will record a deferred effect (either revenue or expense) of
approximately $5 million Canadian dollars.  The resulting revenue
or expense in U.S. dollars from such fluctuations would depend on
the currency rate during the applicable period.

     Distributions on TCP Securities  The TCP Securities are
convertible into common shares of Devon at the option of the
holder.  Beginning in June 1999, Devon can redeem the TCP
Securities for cash at 104.55% of face value if the redemption
occurs in 1999, and thereafter at premiums that decline ratably
to 100% in 2006.  If Devon were to offer to redeem the TCP
Securities, the holders could decide instead to convert the TCP
Securities into Devon common stock.  Assuming all $149.5 million
of TCP Securities are outstanding for the entire year, Devon will
make $9.7 million of distributions in 1999.
     
     Reduction of Carrying Value of Oil and Gas Properties  As of
December 31, 1998, the full cost ceiling exceeded Devon's
carrying value of oil and gas properties, less deferred income
taxes.  This full cost "cushion" was approximately $15 million
for the domestic properties and $43 million for the Canadian
properties.  However, these cushion amounts could easily be
eliminated by declines in oil and/or gas prices between year-end
1998 and the end of any quarter during 1999.  The result would be
a 1999 reduction of the carrying value of oil and gas properties.
     
     Income Taxes  Devon expects its consolidated financial
income tax rate in 1999 to be between 35% and 45%.  These rates
are the combined current and deferred tax rates.  There are
certain items, both in the U.S. and Canada, that will have a
fixed impact on 1999'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 1999 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 Canadian
financial income tax in 1999 will also be increased by
approximately $1 million due to the financial amortization of
certain costs 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 1999's financial income tax rates.
     
     Based on its current expectations of 1999 taxable income,
Devon anticipates its current portion of 1999 income taxes will
be $3 million to $8 million in the U.S. and $2 million to $3
million in Canada.  However, unanticipated revenue and/or expense
fluctuations could easily make these tax estimates inaccurate.
     
     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 1999
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
transactions 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.
     
     Given these limitations, Devon expects its 1999 capital
expenditures for drilling and development efforts to total
between $145 million and $175 million.  These amounts include
between $75 million and $90 million in the U.S. and between $70
million and $85 million in Canada.  Devon expects to spend $20
million to $25 million in the U.S. and $15 million to $20 million
in Canada for drilling and facilities costs related to reserves
classified as proved as of year-end 1998.  Devon also plans to
spend another $35 million to $45 million in the U.S. and $40
million to $50 million in Canada on new, higher risk/reward
projects.
     
     In addition to the above expenditures for drilling and
development, Devon expects to participate in the construction of
an extensive gas gathering system and related CO2 removal
facilities, and a gas processing project, all located in the
Powder River Basin of Wyoming.  The extent to which outside
parties will participate in the project has not yet been
determined. Depending on the final level of participation of
those parties, Devon expects to spend between $60 million to $80
million as its share of the project in 1999.
     
     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 48.4 million shares of
common stock outstanding, 1999 dividends are expected to
approximate $10 million.
     
     Capital Resources and Liquidity  The estimated future
drilling and development activities are expected to be funded
primarily through a combination of working capital and operating
cash flow, with the remainder funded with borrowings from Devon's
credit facilities.  As of December 31, 1998, Devon had $219.7
million available under its $400 million credit facilities.  The
amount of operating cash flow to be generated during 1999 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 for 1999.  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.  SFAS 133 is effective for all fiscal
quarters of fiscal years beginning after June 15, 1999.  Devon
plans to adopt the provision of SFAS 133 in the first quarter of
the year ending December 31, 2000, and is currently evaluating
the effects of this pronouncement.
<PAGE>

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 1998, Devon had financial oil and gas price
hedging instruments in place which represented approximately
180,000 barrels of oil production in the first quarter of 1999,
and approximately 29 Bcf, 12 Bcf, 10 Bcf and 2 Bcf of gas
production in the years 1999, 2000, 2001 and 2002, respectively.
The 1999 hedged oil and gas volumes represent approximately 2%
and 20%, respectively, of expected 1999 total production.  See
"Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations - 1999 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, 1998, a 10% increase in the
underlying commodities' prices would have reduced the fair value
of Devon's commodity hedging instruments by $7.3 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.  The
majority of these fixed price contracts relate to Devon's
Canadian gas production.  For each of the years of 1999 through
2003, Devon's fixed-price gas contracts cover approximately 35
Bcf, 17 Bcf, 12 Bcf, 10 Bcf and 6 Bcf of production,
respectively.  Devon also has Canadian gas volumes subject to
fixed-price contracts in the years from 2004 through 2016, but
the yearly volumes are less than 6 Bcf.  The amount of 1999's
production covered by fixed-price contracts represents
approximately 25% of expected 1999 total production.  See "Item
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - 1999 Estimates."

     Interest Rate Risk.  At December 31, 1998, Devon had long-
term debt outstanding of $405.3 million.  Of this amount, $225
million, or 55%, bears interest at fixed rates averaging 6.8%.
The remaining $180.3 million of debt outstanding at the end of
1998 bears interest at floating rates which averaged 5.9% at the
end of 1998.  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 at the end of 1998
would equal approximately 59 basis points.  Such an increase in
interest rates would increase Devon's 1999 interest expense by
approximately $1 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 Canadian subsidiaries are based on the U.S.
dollar equivalent of such amounts measured in the Canadian
dollar.  Assets and liabilities of the Canadian subsidiaries are
translated to U.S. dollars using the applicable exchange rate as
of the end of a reporting period.  Revenues, expenses and cash
flow are translated using the average exchange rate during the
reporting period.

     Northstar, one of Devon's Canadian subsidiaries, has $225
million of fixed-rate long-term debt that is denominated in U.S.
dollars.  Changes in the currency conversion rate of the Canadian
and U.S. dollars between the beginning and end of a reporting
period increase or decrease the expected amount of Canadian
dollars required to repay the notes.  The amount of such increase
or decrease is required to be included in determining net
earnings for the period in which the exchange rate changes.  The
first principal payments on these notes are not due until 2001.
Until then, the gains or losses caused by the exchange rate
fluctuations have no effect on cash flow.  In 1999, a $0.03
decrease in the Canadian-to-U.S. dollar exchange rate would cause
Devon to record a charge of approximately $11 million.

     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 1999 Devon will sell $60 million at an average
Canadian-to-U.S. exchange rate of $0.726 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 1998 exchange
rate, these swaps would result in decreases to 1999's annual oil
sales of approximately $6 million.  A further $0.03 decrease in
the Canadian-to-U.S. dollar exchange rate in 1999 would result in
an additional decrease in oil sales of approximately $3 million.

     For purposes of the sensitivity analysis described above for
changes in the foreign currency exchange rate, a change in the
rate of $0.03 was used as opposed to a 10% change in the rate.
During the last six 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 1998 rate.
<PAGE>
     
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  Index to Consolidated Financial Statements and Consolidated
                 Financial Statement Schedules

                                                              Page

Independent Auditors' Reports                                  50

Consolidated Financial Statements:
 Consolidated Balance Sheets
   December 31, 1998, 1997 and 1996                            53

 Consolidated Statements of Operations
   Years Ended December 31, 1998, 1997 and 1996                54

 Consolidated Statements of Stockholders' Equity
   Years Ended December 31, 1998, 1997 and 1996                55

 Consolidated Statements of Cash Flows
   Years Ended December 31, 1998, 1997 and 1996                56

 Notes to Consolidated Financial Statements
   December 31, 1998, 1997 and 1996                            57


All  financial  statement  schedules  are  omitted  as  they  are
inapplicable or the required information is immaterial.
<PAGE>                                
                                
                  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,
1998,  1997 and 1996, 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  financial
statements   of  Northstar  Energy  Corporation,  a  wholly-owned
subsidiary,  which  statements reflect total assets  constituting
31%,  32%  and 37% and total revenues constituting 38%, 37%,  and
44%  in  1998,  1997  and  1996,  respectively,  of  the  related
consolidated  totals.    The 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,  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,
1998,  1997  and  1996, 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
January 26, 1999
<PAGE>                                
                                
              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.



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

Calgary, Alberta
Canada
January 20, 1999
<PAGE>                                
                                
                Report of Independent Accountants
                                
                                
To the Board of Directors of
Northstar Energy Corporation


We have audited the consolidated balance sheet of Northstar
Energy Corporation and its subsidiaries (the "Company") at
December 31, 1996 and the related consolidated statements of
operations and comprehensive income (loss), stockholders' equity
and cash flows for the year 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 audit.

We conducted our audit in accordance with Canadian generally
accepted auditing standards.  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, 1996 and the results of its operations
and its cash flow for the year then ended in accordance with
accounting principles generally accepted in the United States.



                                            COOPERS & LYBRAND
                                          Chartered Accountants

Calgary, Alberta, Canada
February 5, 1997
<PAGE>
<TABLE>
            DEVON ENERGY CORPORATION AND SUBSIDIARIES
                  Consolidated Balance Sheets
                (In Thousands, Except Share Data)
<CAPTION>
                                                            December 31,
                                                   1998         1997          1996
Assets
Current assets:
  <S>                                          <C>             <C>          <C>
  Cash and cash equivalents                    $    19,154     42,065       13,417
  Accounts receivable (Note 5)                      83,858     96,828       63,942
  Inventories                                        2,750      4,012        4,310
  Prepaid expenses                                   2,351      3,142        2,311
  Assets held for sale                                   -     43,548      100,836
  Property disposition receivable                        -          -       47,091
  Deferred income taxes (Note 8)                       605        434        1,600
  Investments and other assets                       1,930     23,228          136

    Total current assets                           110,648    213,257      233,643

Property and equipment, at cost, based on
  the full cost method of accounting for oil
  and gas properties (Note 6)                    2,610,511  2,320,735    1,488,336
  Less accumulated depreciation, depletion and
    amortization                                 1,509,583  1,325,452      568,789

                                                 1,100,928    995,283      919,547
Other assets                                        14,780     40,446       30,100

    Total assets                                $1,226,356  1,248,986    1,183,290

Liabilities and stockholders' equity
Current liabilities:
  Accounts payable:
    Trade                                           40,177     46,003       33,796
    Revenues and royalties due to others            12,508     13,898       11,492
  Income taxes payable                                   -      5,029        5,016
  Current portion of long-term debt                      -     48,979       88,835
  Accrued expenses                                  27,971     22,405        7,668

    Total current liabilities                       80,656    136,314      146,807

Other liabilities (Notes 3 and 12)                  34,747     29,464       18,208
Long-term debt (Note 7)                            405,271    305,337       83,000
Deferred income taxes (Note 8)                      33,219     31,825      107,003
Company-obligated mandatorily redeemable convertible
  preferred securities of subsidiary trust holding
  solely 6.5% convertible junior subordinated
  debentures of Devon Energy Corporation (Note 9)  149,500    149,500      149,500
Stockholders' equity (Note 10):
  Preferred stock of $1.00 par value.
    Authorized 3,000,000 shares;
    none issued                                          -          -            -
  Common stock of $.10 par value.
    Authorized 400,000,000 shares; issued
    48,425,000 in 1998, 48,290,000 in 1997, and
    42,878,000 in 1996                               4,842      4,829        4,288
  Additional paid-in capital                       796,992    794,176      556,049
  Retained earnings (accumulated deficit)         (242,909)  (175,346)     131,090
  Accumulated other comprehensive loss             (35,962)   (27,113)     (12,655)

    Total stockholders' equity                     522,963    596,546      678,772

Commitments and contingencies (Notes 12 and 13)
    Total liabilities and stockholders' equity  $1,226,356  1,248,986    1,183,290

See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
           DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Consolidated Statements of Operations
            (In Thousands, Except Per Share Amounts)


<CAPTION>
                                                 Year Ended December 31,
                                               1998        1997        1996

Revenues
  <S>                                        <C>          <C>         <C>
  Oil sales                                  $143,624     207,725     136,023
  Gas sales                                   209,344     219,459     101,443
  Natural gas liquids sales                    16,692      24,920      19,299
  Other                                        17,848      47,555      34,570

    Total revenues                            387,508     499,659     291,335

Costs and expenses
  Lease operating expenses                    113,484     100,897      58,734
  Production taxes                             13,916      19,227      10,880
  Depreciation, depletion and amortization
   (Note 6)                                   123,844     169,108      70,307
  General and administrative expenses          23,554      24,381      15,111
  Northstar Combination expenses               13,149           -           -
  Interest expense (Note 7)                    22,632      18,788      12,662
  Deferred effect of changes in foreign 
    currency exchange rate on subsidiary's
    long-term debt (Note 7)                    16,104       5,860         199
  Distributions on preferred securities of
    subsidiary trust (Note 9)                   9,717       9,717       4,753
  Reduction of carrying value of oil and 
    gas properties (Note 14)                  126,900     625,514           -

    Total costs and expenses                  463,300     973,492     172,646

Earnings (loss) before income tax expense
  (benefit)                                   (75,792)   (473,833)    118,689

Income tax expense (benefit) (Note 8)
  Current                                       7,687      26,857       7,834
  Deferred                                    (23,194)   (200,699)     43,252

    Total income tax expense (benefit)        (15,507)   (173,842)     51,086

Net earnings (loss)                          $(60,285)   (299,991)     67,603

Net earnings (loss) per average common
  share outstanding (Note 1):
    Basic                                      $(1.25)      (6.38)       2.06
    Diluted                                    $(1.25)      (6.38)       1.99

Weighted average common shares
  outstanding - basic (Note 1)                 48,376      47,040      32,812



See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
                DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Consolidated Statements of Stockholders' Equity
                             (In Thousands)

<CAPTION>
                                                                     Accumulated
                                                           Retained     Other
                                               Additional  Earnings    Compre-      Total
                                       Common    Paid-In (Accumulated  hensive  Stockholders'
                                        Stock    Capital    Deficit)     Loss      Equity

<S>                                    <C>       <C>         <C>       <C>         <C>
Balance as of December 31, 1995        $3,258    334,749     68,482    (11,842)    394,647

Comprehensive earnings:
  Net earnings                              -          -     67,603          -      67,603
  Other comprehensive loss - foreign
     currency  translation adjustments      -          -          -       (813)       (813)

  Comprehensive earnings                    -          -          -          -      66,790

Common stock issued                     1,030    221,300          -          -     222,330
Dividends                                   -          -     (4,995)         -      (4,995)

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)

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

Common stock issued                        13      2,816          -          -       2,829
Dividends                                   -          -     (7,278)         -      (7,278)

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



See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
                DEVON ENERGY CORPORATION AND SUBSIDIARIES
                  Consolidated Statements of Cash Flows
                             (In Thousands)

<CAPTION>
                                                                Year Ended December 31,
                                                          1998           1997          1996
Cash flows from operating activities
    <S>                                               <C>              <C>            <C>
    Net earnings (loss)                               $   (60,285)     (299,991)      67,603
    Adjustments to reconcile net earnings to net
      cash provided by operating activities:
        Depreciation, depletion and amortization          123,844       169,108       70,307
        Deferred effect of changes in foreign currency
          exchange rate on subsidiary's long-term debt     16,104         5,860          199
        Reduction of carrying value of oil and gas 
          properties                                      126,900       625,514            -
       (Gain) loss on sale of assets                         (164)      (29,573)     (10,598)
       Deferred income taxes (benefit)                    (23,194)     (200,699)      43,252
       Other                                                  901         2,964       (3,559)
       Changes in assets and liabilities net of effects
         of acquisitions of businesses (Note 2):
           (Increase) decrease in:
             Accounts receivable                           10,160       (17,404)     (24,507)
             Inventories                                    1,173           198         (404)
             Prepaid expenses                                 449          (930)      (2,096)
             Other assets                                     130          (874)      (1,033)
           Increase (decrease) in:
             Accounts payable                              (3,439)          300        4,110
             Income taxes payable                          (5,126)          269        3,501
             Accrued expenses                               7,000           132        1,522
             Long-term other liabilities                   (2,882)        (1,818)     (4,049)

            Net cash provided by operating activities     191,571        253,056     144,248

Cash flows from investing activities
    Proceeds from sale of property and equipment           62,997        180,296      15,059
    Proceeds from sale of investments                      42,584              -      16,951
    Capital expenditures                                 (375,512)      (287,991)   (268,677)
    Increase in equity investment                               -        (32,428)          -
    Increase in other assets                               (2,029)        (7,460)     (6,784)

            Net cash used in investing activities        (271,960)      (147,583)   (243,451)

Cash flows from financing activities
    Proceeds from borrowings on revolving lines of 
      credit                                            1,292,020        817,785     401,623
    Principal payments on revolving lines of credit    (1,236,713)      (690,627)   (449,528)
    Issuance of common stock, net of issuance costs         2,829         12,878       3,278
    Issuance of preferred securities of subsidiary
      trust, net of issuance costs                              -              -     144,665
    Repurchase of common stock                                  -       (217,000)          -
    Dividends paid on common stock                         (7,278)        (6,445)     (4,995)
    Increase in long-term other liabilities (Note  3)       6,760          6,268       1,377

          Net cash provided (used) by financing 
            activities                                     57,618        (77,141)     96,420

Effect of exchange rate changes on cash                      (140)           316          62

Net increase (decrease) in cash and cash equivalents       (22,911)       28,648      (2,721)
Cash and cash equivalents at beginning of year              42,065        13,417      16,138

Cash and cash equivalents at end of year              $     19,154        42,065      13,417

See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
           DEVON ENERGY CORPORATION AND SUBSIDIARIES
           Notes to Consolidated Financial Statements
               December 31, 1998, 1997 and 1996

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 primarily in the
states of New Mexico, Texas, Oklahoma and Wyoming.  Devon's
Canadian activities are primarily in the province of Alberta.
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 for
Devon's oil and gas properties in the United States and Canada.
Capitalized costs are depleted by an equivalent unit-of-production 
method, converting gas to oil at the ratio of one barrel ("Bbl") of 
oil to six thousand cubic feet ("Mcf") 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.

     Devon adopted the provisions of SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of," on January 1, 1996.  SFAS No. 121 requires
that long-lived assets and certain identifiable intangibles be
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may
not be recoverable.  Due to Devon's use of the full cost method
of accounting for its oil and gas properties, SFAS No. 121 does
not apply to Devon's oil and gas property assets which comprise
substantially all of Devon's net property and equipment.
Accordingly, the adoption of SFAS No. 121 did not have an impact
on Devon's financial position or results of operations in 1996.

     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.

Gas Balancing

     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 only if Devon's excess takes
of natural gas volumes exceed its estimated remaining recoverable
reserves.  No receivables are recorded for those wells where
Devon has taken less than its ownership share of gas production.

Hedging Activities

     Devon has periodically entered into oil and gas price swaps
and foreign exchange rate swaps to manage its exposure to oil and
gas price volatility.  The foreign exchange rate swaps mitgate
the effect of volatility in the Canadian-to-U.S. dollar exchange
rate on Canadian oil revenues that are predominantly based on U.S. 
prices.  The hedging instruments are usually placed with counter-
parties 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

     On January 1, 1996, Devon adopted SFAS No. 123, "Accounting
for Stock-Based Compensation," which permits entities to
recognize over the vesting period the fair value of all stock-
based awards on the date of grant.  Alternatively, SFAS No. 123
also allows entities to continue to apply provisions of APB No.
25, "Accounting for Stock Issued to Employees," whereby
compensation expense is recorded on the date of grant only if the
current market price of the underlying stock exceeds the exercise
price.  Companies which continue to apply the provisions of APB
No. 25 are required by SFAS No. 123 to disclose pro forma net
earnings and net earnings per share for employee stock option
grants made in 1995 and subsequent years as if the fair-value-
based method defined in SFAS No. 123 had been applied.  Devon has
elected to continue to apply the provisions of APB No. 25, and
has provided the pro forma disclosures required by SFAS No. 123
in Note 10.

Major Purchasers

     During each of the last three years, Aquila Energy Marketing
Corporation ("Aquila") accounted for more than 10% of Devon's
combined oil, gas and natural gas liquids sales.  Aquila
accounted for 19%, 15% and 12% of such sales in 1998, 1997 and
1996,  respectively.  Also, EOTT Energy Operating Limited
Partnership accounted for 15% of combined oil, gas and natural
gas liquids sales in 1996.

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, net of amounts charged to
affiliated partnerships for administrative and overhead costs,
and net of amounts capitalized pursuant to the full cost method
of accounting.

Net Earnings Per Common Share

     In February, 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 128,
"Earnings Per Share."  SFAS No. 128 revised the previous
calculation methods and presentations of earnings per share.  The
statement required that all prior-period earnings per share data
be restated.  Devon adopted SFAS No. 128 in the fourth quarter of
1997 as permitted by the statement.  The effect of adopting SFAS
No. 128 was not material to Devon's prior period earnings per
share data.

     Under the provisions of SFAS No. 128, 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.

     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 1996.  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.
<TABLE>
<CAPTION>
                                                                             Weighted
                                                                              Average      Net
                                                                               Common    Earnings
                                                                    Net        Shares      Per
                                                                  Earnings  Outstanding   Share
                                                                    (In Thousands)
Year ended December 31, 1996:

  <S>                                                             <C>         <C>         <C>
  Basic earnings per share                                        $67,603     32,812      2.06

  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 $1,837,000)     2,998      2,384

    Potential common shares issuable upon the exercise of
    employee stock options                                              -        271

  Diluted earnings per share                                      $70,601     35,467      1.99
</TABLE>

Comprehensive Earnings (Loss)

     Devon adopted Statement of Financial Accounting Standards
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 in a set of financial statements.  It requires that
all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a
financial statement that is displayed with the same prominence as
other financial statements.  Devon's comprehensive income
information is included in the accompanying consolidated
statements of stockholders' equity.  As of December 31, 1998, the
accumulated other comprehensive loss of $36.0 million included in
stockholders' equity consisted of $35.3 million of foreign currency
translation adjustments and $0.7 million of minimum pension liability
adjustments.  As of December 31, 1997 and 1996, the balance of
accumulated other comprehensive loss consisted solely of foreign
currency translation adjustments. The $0.7 million of minimum
pension liability adjustments included in 1998's comprehensive
loss was net of a $0.5 million deferred tax benefit.  There are
no tax benefits related to the foreign currency translation
adjustments.

Foreign Currency Translation Adjustments

     Devon's only operations outside the United States are in
Canada.  For purposes of foreign currency translation, the
Canadian dollar is the functional currency for Devon's Canadian
operations.  Translation adjustments resulting from translating
the Canadian subsidiaries' foreign currency financial statements
into U.S. dollar equivalents are included in accumulated other
comprehensive loss.

Dividends

     Dividends on Devon's common stock were paid in the first
three quarters of 1996 at a per share rate of $0.03 per quarter.
The dividend rate was increased to $0.05 per share for the fourth
quarter of 1996 and all four quarters of 1997 and 1998.  As
adjusted for the Northstar Combination's pooling-of-interests
method of accounting, annual dividends per share for 1998, 1997
and 1996 were $0.15, $0.14 and $0.15, 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.

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.

     In October, 1996, the American Institute of Certified Public
Accountants issued Statement of Position (SOP) 96-1,
"Environmental Remediation Liabilities."  SOP 96-1 was adopted by
Devon on January 1, 1997.  It requires, among other things, that
environmental remediation liabilities be accrued when the
criteria of SFAS No. 5, "Accounting for Contingencies," have been
met.  SOP 96-1 also provides guidance with respect to the
measurement of the remediation liabilities.  Such accounting is
consistent with Devon's method of accounting for environmental
remediation costs.  Therefore, adoption of SOP 96-1 did not have
a material impact on Devon's financial position or results of
operations.

2.   Business Combinations and Pro Forma Information

     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, 1998, approximately 6.5 
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.  Approximately $7.9 million
of such accrued unpaid costs remained on the consolidated balance
sheet as of December 31, 1998.

     The separate results of operations of Devon and Northstar
for the first nine months of 1998 and the years 1997 and 1996 are
as follows.
<TABLE>
<CAPTION>
                             Nine Months
                           Ended September  Year Ended December 31,
                              30, 1998         1997         1996
                             (Unaudited)
                                         (In Thousands)
Revenues:
   <S>                         <C>           <C>          <C>
   Devon                       $184,506      313,140      164,017
   Northstar                    113,576      186,519      127,318

   Combined                    $298,082      499,659      291,335

Net earnings (loss):
   Devon                        (65,329)      75,292       34,801
   Northstar                      8,532     (375,283)      32,802

   Combined                    $(56,797)    (299,991)      67,603
</TABLE>

     On December 23, 1998, Devon acquired certain natural gas
properties located in northeastern Alberta, Canada, from Wascana
Oil and Gas Partnership, a subsidiary of Canadian Occidental
Petroleums Ltd. (the "Wascana Properties").  Devon acquired the
properties for approximately $57.5 million, which was funded with
bank debt under Devon's 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.)

     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.  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 for proved oil and gas reserves,
$43.5 million for undeveloped leasehold and $110 million for 
other assets.

     On December 31, 1996, Devon acquired all of Kerr-McGee
Corporation's ("Kerr-McGee") North American onshore oil and gas
exploration and production business and properties (the "KMG-NAOS
Properties").  As consideration, Devon issued 9,954,000 shares of
its common stock to Kerr-McGee.  The acquisition was made pursuant
to an October 17, 1996, agreement and plan of merger among Devon,
Kerr-McGee and certain of their subsidiaries.

     Devon recorded the KMG-NAOS Properties at approximately
$221.6 million.  Such value was based on the value of the shares
of Devon common stock issued as determined pursuant to generally
accepted accounting principles.  An additional $30.3 million was
allocated to the KMG-NAOS Properties for the deferred income tax
liability created as a result of the substantially tax-free
nature of the transaction to Kerr-McGee.  Excluding the
additional deferred tax liability, the amount recorded for the
KMG-NAOS Properties includes approximately $195.1 million
allocated to proved oil and gas reserves, $29.0 million allocated
to undeveloped leasehold acquired, $0.6 million allocated to
inventories and other assets acquired and $3.1 million allocated
to certain assumed liabilities.  Including the additional $30.3 
million of deferred tax liability, $220.0 million was allocated 
to proved reserves and $34.4 million to undeveloped leasehold.

     Estimated proved reserves associated with the KMG-NAOS
Properties as of December 31, 1996, were 47 million barrels of
oil equivalent ("MMBoe") in the United States and 15 MMBoe in
Canada.  These reserves were approximately 36% oil and natural
gas liquids and 64% natural gas.  Included in the acquired
reserves were certain proved undeveloped reserves, for which
Devon expected to incur approximately $6 million of future
capital costs.  The United States assets acquired are located
predominantly in the Rocky Mountain, Permian Basin and Mid-
Continent areas of the country.  All of these areas were already
core areas of Devon's operations.  (The quantities of proved
reserves and the estimated development costs stated in this
paragraph are unaudited.)

Pro Forma Information (Unaudited)

     The acquisition of the Wascana Properties, the Morrison
Transaction and the acquisition of the KMG-NAOS Properties as
described above were accounted for by the purchase method of
accounting for business combinations.  Accordingly, the
accompanying 1998, 1997 and 1996 consolidated statements of
operations do not include any revenues or expenses of the Wascana
Properties, the 1997 consolidated statement of operations
includes only nine months of revenues and expenses from the
Morrison Transaction, and the 1996 consolidated statement of
operations does not include any revenues or expenses associated
with the KMG-NAOS Properties or the Morrison Transaction.
Following are Devon's pro forma results for 1998, 1997 and 1996
assuming the acquisition of the Wascana Properties, the Morrison
Transaction and the acquisition of the KMG-NAOS Properties
occurred on January 1, 1996:

<TABLE>
<CAPTION>
                                                   1998
                                                 Pro Forma
                                                 Effect of
                                     Devon        Wascana      Devon
                                   Historical    Properties   Pro Forma
                              (In Thousands, Except Per Share Amounts)

     <S>                            <C>            <C>         <C>
     Total revenues                 $ 387,508      17,570      405,078
     Net earnings (loss)            $ (60,285)      2,835      (57,450)
     Net loss per share -
         basic and diluted             $(1.25)                   (1.19)

<CAPTION>
                                                            1997
                                                   Pro Forma Effect of
                                      Devon       Wascana     Morrison       Devon
                                    Historical   Properties  Transaction   Pro Forma
                                        (In Thousands, Except Per Share Amounts)

     <S>                            <C>            <C>          <C>         <C>
     Total revenues                 $ 499,659      21,695       27,959      549,313
     Net earnings (loss)            $(299,991)      4,325          793     (294,873)
     Net loss per share -
         basic and diluted             $(6.38)                                (5.95)

<CAPTION>
                                                        1996
                                                 Pro Forma Effect of
                                Devon      Wascana    Morrison     KMG-NAOS     Devon
                              Historical  Properties Transaction  Properties  Pro Forma
                                      (In Thousands, Except Per Share Amounts)

     <S>                       <C>          <C>        <C>         <C>         <C>
     Total revenues            $291,335     20,203     113,721     133,167     558,426
     Net earnings                67,603      3,053      16,796      34,647     122,099
     Net earnings per share:
         Basic                    $2.06                                           2.33
         Diluted                  $1.99                                           2.27
</TABLE>
<PAGE>

3.   San Juan Basin Transaction

     Effective January 1, 1995, Devon and an unrelated company
entered into a transaction covering substantially all of Devon's
San Juan Basin coal seam gas properties (the "San Juan Basin
Transaction").  In addition to the cash flow and earnings impact
normally associated with oil and gas production, these properties
also qualify as a "nonconventional fuel source" under the
Internal Revenue Code of 1986.  Consequently, gas produced from
these properties through the year 2002 qualifies for Section 29
tax credits, which as of year-end 1998 were equal to
approximately $1.06 per million Btu ("MMBtu").

     The San Juan Basin Transaction involves approximately 186.2
Bcf, or 93%, of Devon's year-end 1994 coal seam gas reserves, and
has four major parts associated with it.  First, Devon conveyed
to the unrelated party 179 Bcf of the properties' reserves.
However, for financial reporting purposes, Devon retained all of
such reserves and their future production and cash flow through a
volumetric production payment and a repurchase option.  Second,
Devon conveyed outright to the unrelated party 7.2 Bcf of
reserves for a sales price of $5.2 million.  The reserves and
future cash flow associated with this conveyance were not
retained by Devon.  Third, and the source of the most significant
impact of the transaction, Devon receives payments equal to 75%
of the Section 29 tax credits generated by the properties.  And
fourth, Devon retained a 75% reversionary interest in any
reserves in excess of the 186.2 Bcf estimated to exist as of
December 31, 1994.  Each of these parts of the San Juan Basin
Transaction, and their effects on Devon's operations, are
described in more detail in the following paragraphs.

     The production payment retained by Devon is equal to 94.05%
of the first 143.4 Bcf of gas produced from the properties, or
134.9 Bcf.  As such, Devon continues to record gas sales and
associated production and operating expenses and reserves
associated with the production payment.  Production from the
retained production payment is currently estimated to occur over
a period of nine years.

     The conveyance of the properties which are not subject to
the retained production payment or the repurchase option was
accounted for as a sale of oil and gas properties.  Accordingly,
7.2 Bcf of gas reserves were removed from total proved reserves,
and the $5.2 million of proceeds reduced the book value of oil
and gas properties.  The conveyance to the third party is limited
exclusively to the existing wells drilled as of January 1, 1995.
Wells to be drilled in the future, if any, are not included in
this transaction.

     In addition to receiving 94.05% of the properties' net cash
flow through the retained production payment, Devon receives
quarterly payments from the third party equal to 75% of the value
of the Section 29 tax credits which are generated by production
from such properties until the earlier of December 31, 2002, or
until the option to repurchase is exercised.  For the years ended
December 31, 1998, 1997 and 1996, Devon received $10.4 million,
$11.4 million and $11.5 million, respectively, related to the
credits.  Of these amounts, $8.4 million, $8.5 million and $10.3
million were recorded as additional gas sales in 1998, 1997 and
1996, respectively, and $2.0 million, $2.9 million and $1.2
million were recorded as an addition to liabilities in 1998, 1997
and 1996, respectively, as discussed in the following paragraph.
Based on the reserves estimated at December 31, 1998, and an
assumed annual inflation factor of 2%, Devon estimates it will
receive total tax credit payments of approximately $39.9 million
from 1999 through 2002.

     Devon has an option to repurchase the properties at any
time.  The purchase price of such option is equal to the fair
market value of the properties at the time the option is
exercised, as defined in the transaction agreement, less the
production payment balance.  At closing, Devon received $5.6
million associated with reserves to be produced subsequent to the
term of the production payment.  Such amount is included in long-
term "other liabilities" on the accompanying balance sheet.
Since Devon expects to exercise its option to repurchase the
properties, the liability is being increased over time to reflect
the expected option purchase price.  As the purchase price
increases, a portion of the tax credit payments received by Devon
is added to the liability.  As stated above, for the years ended
December 31, 1998, 1997 and 1996, $2.0 million, $2.9 million and
$1.2 million, respectively, of the total amount received for tax
credit payments were added to the liability.  On December 31,
1997, Devon exercised its option to reacquire approximately 20%
of the properties for approximately $1.9 million.  The other
party to the production payment paid Devon $5.3 million in 1997
and $4.8 million in January 1998 in return for Devon agreeing not
to exercise its option on the remaining 80% of the properties
through June 30, 1998.  (This agreement does not limit Devon's
right to exercise its option in 1999 or beyond.)  The $5.3
million that Devon received in 1997, net of the $1.9 million paid
for the partial repurchase, and the $4.8 million received in 1998
were added to the repurchase liability.  The repurchase liability
totaled $21.0 million at the end of 1998.

     Devon has retained a 75% reversionary interest in the
properties' reserves in excess, if any, of the 186.2 Bcf of
reserves estimated to exist at December 31, 1994.  The terms of
the transaction provide that the third party will pay 100% of the
capital necessary to develop any such incremental reserves for
its 25% interest in such reserves.  Devon's repurchase option
also includes the right to purchase this incremental 25%.
However, the $21.0 million of other liabilities recorded as of
year-end 1998, does not include any amount related to such
reserves.

4.   Supplemental Cash Flow Information

     Cash payments for interest in 1998, 1997 and 1996 were
approximately $24.5 million, $16.7 million and $12.4 million,
respectively.  Cash payments for federal, state and foreign
income taxes in 1998, 1997 and 1996 were approximately $14.2
million, $26.9 million and $5.3 million, respectively.

     The 1997 Morrison Transaction and the 1996 acquisition of
the KMG-NAOS Properties involved non-cash consideration as
presented below:
<TABLE>
<CAPTION>
                                                1997        1996
                                                 (In Thousands)

          <S>                                 <C>          <C>
          Value of common stock issued        $441,590     221,576
          Liabilities assumed                  111,345       3,099
          Deferred tax liability created       128,497      30,308

          Fair value of assets acquired       $681,432     254,983
</TABLE>

5.   Accounts Receivable

     The components of accounts receivable included the
following:
<TABLE>
<CAPTION>
                                                    December 31,
                                              1998      1997      1996
                                                  (In Thousands)

     Oil, gas and natural gas liquids
         <S>                                <C>        <C>       <C>
         revenue accruals                   $46,360    52,974    39,096
     Joint interest billings                 23,636    25,283    19,042
     Other                                   14,262    19,398     6,642

                                             84,258    97,655    64,780
     Allowance for doubtful accounts           (400)     (827)     (838)

     Net accounts receivable                $83,858    96,828    63,942
</TABLE>

6.   Property and Equipment

     Property and equipment included the following:
<TABLE>
<CAPTION>
                                                          December 31,
                                                 1998        1997         1996
                                                       (In Thousands)
     Oil and gas properties:
       <S>                                   <C>           <C>         <C>
       Subject to amortization               $ 2,413,376   2,157,104   1,368,208
       Not subject to amortization:
        Acquired in 1998                          46,302           -           -
        Acquired in 1997                          51,961      60,399           -
        Acquired in 1996                          33,941      36,942      46,879
        Acquired in 1995                          12,491      14,495      21,689
        Acquired in 1994                           5,182       7,028      10,638
        Acquired in 1993                           4,027       4,069       5,293
        Acquired in 1992                           7,773       7,814       8,245

       Accumulated depreciation, depletion
        and amortization                      (1,498,075) (1,316,343)   (561,935)

          Net oil and gas properties           1,076,978     971,508     899,017

     Other property and equipment                 35,458      32,884      27,384

     Accumulated depreciation and amortization   (11,508)     (9,109)     (6,854)

          Net other property and equipment        23,950      23,775      20,530

     Property and equipment, net of
       accumulated depreciation,
       depletion and amortization            $ 1,100,928     995,283     919,547
</TABLE>
     Depreciation, depletion and amortization expense consisted
of the following components:
<TABLE>
<CAPTION>
                                                     Year Ended December 31,
                                                 1998         1997         1996
                                                        (In Thousands)
     Depreciation, depletion and amortization
     <S>                                       <C>           <C>          <C>
       of oil and gas properties               $119,719      164,977      67,832
     Depreciation and amortization of other
       property and equipment                     3,964        3,566       1,989
     Amortization of other assets                   161          565         486

       Total expense                           $123,844      169,108      70,307
</TABLE>

7.   Long-term Debt and Related Expenses

     A summary of Devon's long-term debt is as follows:
<TABLE>
<CAPTION>
                                                     December 31,
                                               1998      1997       1996
                                                    (In Thousands)

<S>                                          <C>        <C>        <C>
Notes payable to banks                       $180,271   219,316    96,835
6.76% senior notes due July 19, 2005           75,000    75,000    75,000
6.79% senior notes due March 2, 2009          150,000         -         -
7.03% senior notes due November 7, 2005             -    60,000         -

                                              405,271   354,316   171,835
Less amount classified as current                   -    48,979    88,835

Net long-term debt                           $405,271   305,337    83,000
</TABLE>

     Maturities of long-term debt as of December 31, 1998, are as
follows (in thousands):
<TABLE>
     <C>                        <S>
     1999                        $      -
     2000                           7,264
     2001                          22,264
     2002                          22,264
     2003                          57,264
     2004 and thereafter          296,215

     Total                       $405,271
</TABLE>

     On December 11, 1998, Devon entered into new unsecured long-
term credit facilities aggregating $400 million (the "Credit
Facilities").  The Credit Facilities include a U.S. facility of
$205 million (the "U.S. Facility") and a Canadian facility of
$195 million (the "Canadian Facility").  The Credit Facilities
replaced Devon's and Northstar's separate credit facilities that
were in place prior to the Northstar Combination.  Of the $180.3
million borrowed against the Credit Facilities at December 31,
1998, $35 million was borrowed under the U.S. Facility and $145.3
million was borrowed under the Canadian Facility.  Amounts
borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six
months.  Such rates are generally less than the prime rate.
Devon may also elect to borrow at the prime rate.  The average
interest rate on the $180.3 million of debt outstanding
at December 31, 1998, was 5.9%.  The Credit Facilities also
provide for an annual facility fee of $0.4 million that is
payable quarterly.  The average interest rate on bank debt
outstanding under the previous facilities at December 31, 1997
and 1996 was 4.8% and 3.8%, respectively.
     
     The $205 million U.S. Facility consists of a Tranche A
facility of $130 million and a Tranche B facility of $75 million.
The Tranche A facility matures on December 10, 2003.  Devon may
borrow funds under the Tranche B facility until December 10, 1999
(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 not more than 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.  All $35 million of
debt outstanding under the U.S. Facility at December 31, 1998,
was borrowed under the Tranche A facility.
     
     Devon may borrow funds under the $195 million Canadian
Facility until December 10, 1999 (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 not more than 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 four years, with the remaining balance due five years
and one day following the end of the Canadian Facility Revolving
Period.  The yearly maturity schedule shown earlier in this note
assumes that the Canadian Facility Revolving Period is not
extended past December 10, 1999.

     Northstar issued the 6.76% notes in a private placement in
1995.  The notes are unsecured and are payable in five annual
installments of $15 million each beginning in 2001.
     
     Northstar issued the 6.79% notes in a private placement in
1998.  The notes are unsecured and are 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.
     
     The agreements governing the Credit Facilities and the
senior notes contain certain covenants and restrictions,
including maintenance of certain debt-to-capitalization and debt-
to-EBITDA ratios and restrictions on additional borrowings.  At
December 31, 1998, Devon and Northstar were in compliance with
such covenants and restrictions.
     
    See Note 9 for a description of certain convertible
debentures issued in 1996 to a Devon affiliate.

Interest Expense
     
     Following are the components of interest expense for the
years 1998, 1997 and 1996:
<TABLE>
<CAPTION>
                                                 1998      1997      1996
                                                     (In Thousands)
     
     <S>                                       <C>        <C>       <C>
     Interest based on debt outstanding        $21,814    14,345    11,234
     Facility and agency fees                      632       598       681
     Amortization of capitalized loan costs        156       118        42
     Penalty on early retirement of debt             -     3,323         -
     Hedging gains                                (188)     (410)     (205)
     Other                                         218       814       910
     
     Total interest expense                    $22,632    18,788    12,662
</TABLE>

     The above amounts classified as "other" in 1997 and 1996
were primarily related to adjustments of certain oil and gas
property acquisitions.
     
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 are debt payable by Northstar.  However, the notes are
denominated in U.S. dollars.  Changes in the exchange rate between
the U.S. dollar and the Canadian dollar from the dates the notes
were issued to the dates of repayment will increase or decrease
the expected amount of Canadian dollars eventually required to
repay the notes.  Such changes in the Canadian dollar equivalent
of the debt are required to be included in determining net
earnings for the period in which the exchange rate changes.  The
rate of conversion of Canadian dollars to U.S. dollars declined in
each of the years 1998, 1997 and 1996.  Therefore, $16.1 million,
$5.9 million and $0.2 million, respectively, were charged to
expense in each of these years.

8.   Income Taxes

     At December 31, 1998, Devon had the following carryforwards
available to reduce future income taxes:
<TABLE>
<CAPTION>
                                              Years of       Carryforward
       Types of Carryforward                 Expiration         Amounts
                                                            (In Thousands)

    <S>                                      <C>                <C>
    Net operating loss - U.S. federal        2007 - 2008        $ 5,501
    Net operating loss - various states      1999 - 2011        $12,948
    Net operating loss - Canada              2000 - 2005        $53,170
</TABLE>

    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 1998, 1997 and 1996
were as follows:
<TABLE>
<CAPTION>
                                               Year Ended December 31,
                                              1998       1997       1996
                                                   (In Thousands)
     Earnings (loss) before income taxes:
      <S>                                  <C>         <C>         <C>
      U.S.                                 $(95,184)   106,665     59,299
      Canada                                 19,392   (580,498)    59,390

      Total                                $(75,792)  (473,833)   118,689

     Current income tax expense:
      U.S. federal                            4,801     18,659      6,147
      Various states                            911      2,521        562
      Canada                                  1,975      5,677      1,125

      Total current tax expense               7,687     26,857      7,834

     Deferred income tax expense (benefit):
      U.S. federal                          (29,524)    17,025     14,185
      Various states                         (4,836)     1,578      3,604
      Canada                                 11,166   (219,302)    25,463

      Total deferred tax expense (benefit)  (23,194)  (200,699)    43,252

     Total income tax expense (benefit)    $(15,507)  (173,842)    51,086
</TABLE>

     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:
<TABLE>
<CAPTION>
                                            Year Ended December 31,
                                            1998      1997      1996

     <S>                                    <C>       <C>        <C>
     U.S. statutory tax (benefit) rate      (35)%     (35)%      35%
     Non-deductible expenses                 15         -         -
     Nonconventional fuel source credits     (4)        -         -
     State income taxes                      (3)        -         2
     Taxation on foreign operations           8        (2)        5
     Effect of San Juan Basin Transaction    (1)        -         1

     Effective income tax (benefit) rate    (20)%     (37)%      43%
</TABLE>

     The tax effects of temporary differences that gave rise to
significant portions of the deferred tax assets and liabilities
at December 31, 1998, 1997 and 1996 are presented below:
<TABLE>
<CAPTION>
                                                               December 31,
                                                        1998       1997       1996
                                                              (In Thousands)

     Deferred tax assets:
      <S>                                            <C>          <C>        <C>
      Net operating loss carryforwards               $ 21,818     21,076     11,581
      Statutory depletion carryforwards                     -          -        412
      Investment tax credit carryforwards                   -         19         42
      Minimum tax credit carryforwards                      -          -      5,624
      Production payments                              19,105     18,504     19,685
      Other                                             3,188      7,154      3,323

        Total gross deferred tax assets                44,111     46,753     40,667
        Less valuation allowance                          100        100        100

        Net deferred tax assets                        44,011     46,653     40,567
     Deferred tax liabilities:
      Property and equipment, principally due
        to differences in depreciation, and
        the expensing of intangible drilling
        costs for tax purposes                        (76,156)   (76,523)  (145,970)
      Other                                              (469)    (1,521)         -

      Total deferred tax liabilities                  (76,625)   (78,044)  (145,970)

          Net deferred tax liability                 $(32,614)   (31,391)  (105,403)
</TABLE>

     As shown in the above schedule, Devon has recognized $44.0
million of net deferred tax assets as of December 31, 1998.  Such
amount consists primarily of $21.8 million of various
carryforwards available to offset future income taxes, and $19.1
million of net tax basis in production payments.  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
1999 and 2011 and Canadian carryforwards which expire primarily
between 2000 and 2005.  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 1999 and 2002.  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,
1998, related to depletion carryforwards acquired in a 1994
merger.

     The $19.1 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 which is described in such note.  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 $19.1 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 newly-formed affiliate
Devon Financing Trust, completed the issuance of $149.5 million
of 6.5% trust convertible preferred securities (the "TCP
Securities") in a private placement.  Devon Financing Trust
issued 2,990,000 shares of the TCP Securities at $50 per share.
Each TCP Security is 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.

     The sole assets of Devon Financing Trust are the Convertible
Debentures.  The Convertible Debentures and the related TCP
Securities mature on June 15, 2026.  However, Devon and Devon
Financing Trust may redeem the Convertible Debentures and the TCP
Securities, respectively, in whole or in part, on or after June
18, 1999.  For the first twelve months thereafter, redemptions
may be made at 104.55% of the principal amount.  This premium
declines proportionally every twelve months until June 15, 2006,
when the redemption price becomes fixed at 100% of the principal
amount.  If Devon redeems any Convertible Debentures prior to the
scheduled maturity date, Devon Financing Trust must redeem TCP
Securities having an aggregate liquidation amount equal to the
aggregate principal amount of Convertible Debentures so redeemed.

     Devon has guaranteed the payments of distributions and other
payments on the TCP Securities only if and to the extent that
Devon Financing Trust has funds available therefor.  Such
guarantee, when taken together with Devon's obligations under the
Convertible Debentures and related indenture and declaration of
trust, provide a full and unconditional guarantee of amounts due
on the TCP Securities.

     Devon owns all the common securities of Devon Financing
Trust.  As such, the accounts of Devon Financing Trust are
included in Devon's consolidated financial statements after
appropriate eliminations of intercompany balances and
transactions.  The distributions on the TCP Securities are
recorded as a charge to pre-tax earnings on Devon's consolidated
statements of operations, and such distributions are 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 three million shares of preferred stock, par
value $1.00 per share (the "Preferred Stock").  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.

     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 1998, 6.5 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 150,000 shares of
the Preferred Stock as Series A Junior Participating Preferred
Stock (the "Series A Preferred Stock") in connection with the
adoption of the share rights plan described later in this note.
At December 31, 1998, there were no shares of Series A Preferred
Stock issued or outstanding.  The Series A 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 Preferred Stock.  Holders of the
Series A 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 Preferred
Stock is neither redeemable nor convertible.  The Series A
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,
1998, 12 participants held the 251,100 options outstanding under
the 1988 Plan, and 23 participants held the 805,300 options
outstanding under the 1993 Plan.

     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.  Approximately 150
employees and nine members of the board of directors were
eligible to participate in the 1997 Plan at year-end 1998.

     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, 1998, approximately 150 participants held the
1,126,450 options outstanding under the 1997 Plan.   There were
1,873,550 options available for future grants as of December 31,
1998.

     In addition to the stock options outstanding under the 1988
Plan, 1993 Plan and 1997 Plan, there were 1,272,842 stock options
outstanding at the end of 1998 that were assumed as part of the
Northstar Combination.  Northstar had granted these options prior
to the Northstar Combination.  As part of the Northstar
Combination, the options were assumed by Devon and converted to
Devon options at the exchange rate of 0.235 Devon options for
each Northstar option.  The 1,272,842 options were held by 134
employees.

     A summary of the status of Devon's stock option plans as of
December 31, 1996, 1997 and 1998, and changes during each of the
years then ended, is presented below.  The following table
includes the Northstar options converted to the equivalent number
of Devon options.

<TABLE>
<CAPTION>
                                     Options Outstanding    Options Exercisable
                                                 Weighted               Weighted
                                                 Average                Average
                                      Number     Exercise    Number     Exercise
                                   Outstanding    Price    Exercisable    Price

<S>                                 <C>          <C>         <C>         <C>
Balance at December 31, 1995        1,740,798    $25.253     933,936     $22.727
 Options granted                      518,691    $33.411
 Options exercised                   (142,886)   $17.889
 Options forfeited                    (90,820)   $36.640

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
</TABLE>

     The weighted average fair values of options granted during
1998, 1997 and 1996 were $10.72, $10.12 and $11.88, 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 1998, 1997 and
1996, respectively: risk-free interest rates of 4.9%, 6.0% and
6.5%; dividend yields of 0.5%, 0.1% and 0.3%; expected lives of
4, 4 and 5 years; and volatility of the price of the underlying
common stock of 33.9%, 30.7% and 36.8%.

     The following table summarizes information about Devon's stock
options which were outstanding, and those which were exercisable,
as of December 31, 1998:
<TABLE>
<CAPTION>
                            Options Outstanding                  Options Exercisable
                                    Weighted     Weighted                     Weighted
  Range of                          Average      Average                      Average
  Exercise            Number       Remaining     Exercise        Number       Exercise
   Prices          Outstanding        Life         Price       Exercisable      Price

<S>                 <C>            <C>            <C>           <C>            <C>
$8.375-$25.440      1,192,391      3.9 years      $22.408       1,173,591      $22.382
$25.698-$29.850       960,724      8.3 years      $28.905         355,074      $28.529
$30.996-$33.606       520,863      5.3 years      $32.094         325,348      $32.275
$35.286-$42.896       781,714      4.6 years      $37.087         781,714      $37.087

                    3,455,692      5.5 years      $28.995       2,635,727      $28.793
</TABLE>

     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 1998, 1997 and 1996 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.
<TABLE>
<CAPTION>
                                        Year Ended December 31,
                                    1998          1997         1996
                               (In Thousands, Except Per Share Amounts)

     Net earnings (loss):
         <S>                      <C>           <C>            <C>
         As reported              $(60,285)     (299,991)      67,603
         Pro forma                $(72,770)     (306,992)      62,619

     Net earnings (loss) per share:
         As reported:
              Basic                 $(1.25)        (6.38)        2.06
              Diluted               $(1.25)        (6.38)        1.99
         Pro forma:
              Basic                 $(1.50)        (6.52)        1.91
              Diluted               $(1.50)        (6.52)        1.85
</TABLE>

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, 1998, 1997 and 1996.
<TABLE>
<CAPTION>
                                                      1998                     1997                      1996
                                               Carrying      Fair       Carrying     Fair        Carrying      Fair
                                                Amount       Value       Amount      Value        Amount       Value
                                                                            (In Thousands)

<S>                                           <C>            <C>          <C>        <C>           <C>         <C>
Investments                                   $   1,930      1,930        2,409      5,125         3,972       5,150
Oil and gas price hedge agreements            $       -      1,988            -      3,569             -      (4,453)
Foreign exchange hedge agreements             $       -     (9,310)           -     (5,038)            -       1,825
Long-term debt (including current portion)    $(405,271)  (421,675)    (354,316)  (360,294)     (171,835)   (170,615)
TCP Securities                                $(149,500)  (171,400)    (149,500)  (218,800)     (149,500)   (196,600)
</TABLE>

     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 market value at December
31, 1998, 1997 and 1996.

     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 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.

     As of December 31, 1998, Devon had one open oil price
hedging instrument covering 2,000 barrels per day of Canadian
production for the first three months of 1999.  The price to be
received for this production is $20.01 per barrel, while Devon
will pay the counterparty the floating NYMEX price.

     In additional to the open oil hedge described in the above
paragraph, Devon also had open foreign currency hedging
instruments at the end of 1998.  These hedging instruments offset
a portion  of the exposure to currency fluctuations on Devon's
Canadian oil sales that are based on U.S. 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, 1998, Devon had open foreign currency hedging
instruments in which it will sell $60 million in 1999 and $30
million in 2000 at average Canadian-to-U.S. dollar exchange rates
of $0.726 and $0.727, respectively.  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 aditional $10 million in each of the years 2000 and 2001 at
average Canadian-to-U.S. dollar exchange rates of $0.713 and
$0.710, respectively.  Under these agreements, Devon will buy the
same amount of dollars in each year at the floating exchange
rate.

     The following table covers Devon's notional volumes and
pricing on open natural gas hedging instruments as of December
31, 1998:
<TABLE>
<CAPTION>
                                                     Year of Production
                                                1999    2000    2001   2002

     <S>                                       <C>     <C>     <C>    <C>
     Volumes (billion British thermal units)   27,400  12,336  9,650  1,580
     Average price to be received               $1.79    1.77   1.89   1.80
</TABLE>

     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, San
Juan Basin and Permian Basin.

     Devon's 1998, 1997 and 1996 consolidated balance sheets
include deferred revenues of $1.0 million, $3.8 million and $6.0
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 1998 will
be recognized as oil and gas sales over periods ranging from ten
months to two years as the hedged oil and gas production occurs.

12.  Retirement Plans

     Devon has a defined benefit retirement plan (the "Basic
Plan") which is non-contributory and includes 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 Plan 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
Plan 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.

     The following table sets forth the aggregate funded status
of Devon's Basic Plan and Supplementary Plans and related amounts
recognized in Devon's balance sheets:
<TABLE>
<CAPTION>
                                                            December 31,
                                                     1998       1997      1996
                                                          (In Thousands)
Change in benefit obligation:
  <S>                                              <C>         <C>       <C>
  Benefit obligation at beginning of year          $11,659     8,029     7,027
  Service cost                                         985       706       557
  Interest cost                                        935       747       569
  Amendments                                           293         -         -
  Actuarial gain                                     1,773     1,463        (6)
  Benefits paid                                       (504)     (349)     (118)
  Establishment of new plan                              -     1,063         -

  Benefit obligation at end of year                 15,141    11,659     8,029

Change in plan assets:
  Fair value of plan assets at beginning of year     6,036     5,022     4,227
  Actual return on plan assets                         (87)      366       453
  Employer contributions                               886       997       460
  Benefits paid                                       (504)     (349)     (118)

  Fair value of plan assets at end of year           6,331     6,036     5,022

Benefit obligation in excess of plan assets         (8,810)   (5,623)   (3,007)

Unrecognized net actuarial loss                      4,730     2,448       965
Unrecognized prior service cost                      1,822     1,973     1,104

Net amount recognized                              $(2,258)   (1,202)     (938)

<CAPTION>
                                                           December 31,
                                                    1998       1997       1996
                                                           (In Thousands)

The net amounts recognized in the consolidated
 balance sheets consist of:
  Accrued benefit cost                             (2,258)    (1,202)     (938)
  Additional minimum liability                     (2,987)    (2,557)   (1,013)
  Intangible asset                                  1,808      2,557     1,013
  Accumulated other comprehensive loss              1,179         -          -

  Net amount recognized                           $(2,258)   (1,202)      (938)
</TABLE>

Net pension expense for Devon's defined benefit plans included
the following components:
<TABLE>
<CAPTION>
                                           Year Ended December 31,
                                           1998      1997     1996
                                                (In Thousands)
  <S>                                    <C>        <C>       <C>
  Service cost                           $  985       706      557
  Interest cost                             935       747      569
  Expected return on plan assets           (532)     (445)    (382)
  Amortization of prior service cost        256       194       96
  Recognized net actuarial loss             111        59       64

  Net periodic pension expense           $1,755     1,261      904
</TABLE>

     The weighted average discount rate used in determining the
actuarial present value of the projected benefit obligation in
1998, 1997 and 1996 was 6.5%, 7.0% and 7.5%, respectively.  The
rate of increase in future compensation levels was 5% for all
three years.  The expected long-term rate of return on assets was
8.5% for all three years.

     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 $1.0
million, $0.5 million and $0.2 million for the years ended
December 31, 1998, 1997 and 1996, respectively.

     Devon has defined contribution plans for its Canadian
employees.  Devon contributes between 6% and 10% of the
employee's base compensation, depending upon the employee's
classification.  Such contributions are subject to maximum
amounts allowed under the Income Tax Act (Canada).

     Devon also has a savings plan for its Canadian employees.
Under the savings plan, Devon contributes an amount equal to 2%
of the base salary of each employee.  The employees may elect to
contribute up to 4% of their salary.  If such employee
contributions are made, they are matched by additional Devon
contributions.

     During the years 1998, 1997 and 1996, Devon's combined
contributions to the Canadian defined contribution plan and the
Canadian savings plan were $1.8 million, $1.2 million and $0.4
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 after
consideration of recorded accruals.

     The State of New Mexico on December 29, 1995, assessed Devon
and other producers of gas from the San Juan Basin a "natural gas
processors tax."  Devon's tax assessment for the years 1990
through 1995 was approximately $0.6 million, and the state also
assessed another $0.3 million of penalties and interest.  All of
the assessment relates to nonconventional gas.  Devon paid these
assessments in January 1996, as well as an additional $0.2
million each year for 1998, 1997 and 1996 taxes which were paid
monthly throughout such years, so that it could begin the
necessary procedures of applying for a refund.  This tax
historically was paid by the owners of natural gas processing
plants, not the gas producers, and was assessed for the privilege
of processing natural gas.  While Devon's nonconventional gas is
purified through a plant prior to the actual sales point, such
purification is only for the purpose of removing CO2.  Also,
Devon does not own an interest in such plant.  For these and
other reasons, Devon does not believe the assessment of the
additional tax and the related penalties and interest is valid.
The State of New Mexico in 1997 denied Devon's initial refund
application made through the normal administrative processes.
Subsequently, in late 1997, Devon filed a suit asking that the
assessments be reversed.  At this time, it is not possible to
determine the eventual outcome of this matter.  Devon has not
expensed in its financial statements the taxes, penalties and
interest paid, but rather has recorded the $1.5 million total as
a receivable.

     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, 1998:
<TABLE>
<CAPTION>
        Year ending December 31,                  (In Thousands)
         <S>                                           <C>
         1999                                          $2,744
         2000                                           2,631
         2001                                           1,266
         2002                                             505
         2003                                             230
         Thereafter                                       102

           Total minimum lease payments required      $ 7,478
</TABLE>

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

                                                  (In Thousands)
         <S>                                           <C>
         1998                                          $3,119
         1997                                          $2,619
         1996                                          $1,735
</TABLE>

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.

     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:
<TABLE>
<CAPTION>
                                                                  Total
                                                         Year Ended December 31,
                                                       1998       1997        1996
                                                             (In Thousands)
    Property acquisition costs:
     <S>                                             <C>         <C>        <C>
     Proved, excluding deferred income taxes         $135,167    510,331    201,276
     Deferred income taxes                             21,382     94,822     22,557

     Total proved, including deferred income taxes   $156,549    605,153    223,833

     Unproved, excluding deferred income taxes         42,305     50,336     40,202
     Deferred income taxes                                661      6,082      5,472

     Total unproved, including deferred income taxes $ 42,966     56,418     45,674

    Exploration costs                                $ 85,614     54,640     27,940
    Development costs                                $152,105    162,244    118,876

<CAPTION>
                                                                 Domestic
                                                        Year Ended December 31,
                                                       1998        1997       1996
                                                             (In Thousands)
    Property acquisition costs:
     Proved, excluding deferred income taxes         $27,349      10,891    150,546
     Deferred income taxes                                 -       2,084     15,257

     Total proved, including deferred income taxes   $27,349      12,975    165,803

     Unproved, excluding deferred income taxes        26,764       7,582     26,073
     Deferred income taxes                                 -        (100)     5,472

     Total unproved, including deferred income taxes $26,764       7,482     31,545

    Exploration costs                                $35,686      18,326      2,708
    Development costs                                $76,986      79,943     73,468
<CAPTION>
                                                                 Canada
                                                        Year Ended December 31,
                                                      1998        1997        1996
                                                             (In Thousands)
    Property acquisition costs:
     Proved, excluding deferred income taxes        $107,818     499,440     50,730
     Deferred income taxes                            21,382      92,738      7,300

     Total proved, including deferred income taxes  $129,200     592,178     58,030

     Unproved, excluding deferred income taxes        15,541      42,754     14,129
     Deferred income taxes                               661       6,182          -

     Total unproved, including deferred income 
      taxes                                         $ 16,202      48,936     14,129

    Exploration costs                               $ 49,928      36,314     25,232
    Development costs                               $ 75,119      82,301     45,408
</TABLE>

    Pursuant to the full cost method of accounting, Devon
capitalizes certain of its general and administrative expenses
which are related to property acquisition, exploration and
development activities.  Such capitalized expenses, which are
included in the costs shown in the preceding tables, were $9.6
million, $7.5 million and $4.9 million in the years 1998, 1997
and 1996, respectively.

    Due to the substantially tax-free nature of the acquisition
of the KMG-NAOS properties to Kerr-McGee, Devon recorded
additional deferred tax liabilities of $28.0 million in 1996.  As
shown in the preceding 1996 tables, the deferred tax liabilities
caused an additional $22.5 million to be allocated to proved oil
and gas reserves and an additional $5.5 million to be allocated
to unproved properties.

    During 1997, various uncertainties that existed at year-end
1996 regarding the tax basis and liabilities assumed in the KMG-
NAOS transaction 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.

<TABLE>
<CAPTION>
                                                                            Total
                                                                  Year Ended December 31,
                                                                 1998       1997      1996
                                                          (In Thousands, Except Per Equivalent
                                                                      Barrel Amounts)

<S>                                                           <C>         <C>       <C>
Oil, gas and natural gas liquids sales                        $ 369,660   452,104   256,765
Production and operating expenses                              (127,400) (120,124)  (69,614)
Depreciation, depletion and amortization                       (119,719) (164,977)  (67,832)
Reduction of carrying value of oil and gas properties          (126,900) (625,514)        -
Income tax (expense) benefit                                    (19,385)  159,511   (45,870)

Results of operations for oil and gas producing activities    $ (23,744) (299,000)   73,449

Depreciation, depletion and amortization per equivalent
    barrel of production                                          $3.32      4.86      3.69

<CAPTION>
                                                                          Domestic
                                                                  Year Ended December 31,
                                                                1998        1997      1996
                                                           (In Thousands, Except Per Equivalent
                                                                      Barrel Amounts)

Oil, gas and natural gas liquids sales                       $ 208,629    273,860   162,558
Production and operating expenses                              (77,829)   (75,758)  (42,226)
Depreciation, depletion and amortization                       (76,327)   (73,091)  (41,538)
Reduction of carrying value of oil and gas properties         (126,900)         -         -
Income tax (expense) benefit                                    18,230    (44,648)  (27,796)

Results of operations for oil and gas producing activities   $ (54,197)    80,363    50,998

Depreciation, depletion and amortization per equivalent
    barrel of production                                         $4.24       4.13      3.88

<CAPTION>
                                                                           Canada
                                                                  Year Ended December 31,
                                                                1998        1997      1996
                                                           (In Thousands, Except Per Equivalent
                                                                      Barrel Amounts)

Oil, gas and natural gas liquids sales                       $ 161,031    178,244    94,207
Production and operating expenses                              (49,571)   (44,366)  (27,388)
Depreciation, depletion and amortization                       (43,392)   (91,886)  (26,294)
Reduction of carrying value of oil and gas properties                -   (625,514)        -
Income tax (expense) benefit                                   (37,615)   204,159   (18,074)

Results of operations for oil and gas producing activities   $  30,453   (379,363)   22,451

Depreciation, depletion and amortization per equivalent
    barrel of production                                         $2.41       5.64      3.42
</TABLE>

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 Statement of Financial Accounting
Standards 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, 1998.
Approximately 93%, 92% and 94%, of the respective year-end 1998,
1997 and 1996 domestic proved reserves were calculated by the
independent petroleum consultants of LaRoche Petroleum
Consultants, Ltd.  The remaining percentages of domestic reserves
are based on Devon's own estimates.  All of the Canadian proved
reserves were calculated by the independent petroleum consultants
of Paddock Lindstrom & Associates and AMH Group Ltd. in 1998,
1997 and 1996, as well as John P. Hunter & Associates, Ltd., in
1997.
<TABLE>
<CAPTION>
                                                         Total
                                                                   Natural
                                               Oil        Gas    Gas Liquids
                                             (MBbls)     (MMcf)    (MBbls)
<S>                                           <C>        <C>        <C>
Proved reserves as of December 31, 1995       58,999     649,746    11,550
    Revisions of estimates                     4,982     (31,569)    1,022
    Extensions and discoveries                 4,433     149,049     1,154
    Purchase of reserves                      21,189     252,122     2,130
    Production                                (6,780)    (62,186)   (1,255)
    Sale of reserves                          (2,668)    (58,843)     (411)

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

Proved developed reserves as of:
    December 31, 1995                           43,236   597,564     8,230
    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

<CAPTION>
                                                       Domestic
                                                                  Natural
                                                Oil      Gas    Gas Liquids
                                              (MBbls)   (MMcf)    (MBbls)

Proved reserves as of December 31, 1995        44,466   363,846     9,469
    Revisions of estimates                      2,365     4,359     1,096
    Extensions and discoveries                  3,680    14,849       852
    Purchase of reserves                       13,659   209,064     1,246
    Production                                 (3,816)  (35,714)     (952)
    Sale of reserves                             (403)   (1,743)      (16)

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

Proved developed reserves as of:
    December 31, 1995                          28,703   311,664     6,149
    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
<CAPTION>
                                                          Canada
                                                                   Natural
                                                Oil      Gas     Gas Liquids
                                              (MBbls)   (MMcf)     (MBbls)
Proved reserves as of December 31, 1995        14,533   285,900     2,081
    Revisions of estimates                      2,617   (35,928)      (74)
    Extensions and discoveries                    753   134,200       302
    Purchase of reserves                        7,530    43,058       884
    Production                                 (2,964)  (26,472)     (303)
    Sale of reserves                           (2,265)  (57,100)     (395)

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

Proved developed reserves as of
    December 31, 1995                          14,533   285,900     2,081
    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
</TABLE>

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:
<TABLE>
<CAPTION>
                                                           Total
                                                         December 31,
                                               1998         1997        1996
                                                       (In Thousands)

    <S>                                    <C>           <C>         <C>
    Future cash inflows                    $ 2,984,585   3,728,815   4,972,804
    Future costs:
     Development                              (113,139)   (120,277)    (90,638)
     Production                             (1,214,426) (1,386,943) (1,377,410)
    Future income tax expense                 (125,975)   (399,972)   (953,748)

    Future net cash flows                    1,531,045   1,821,623   2,551,008
    10% discount to reflect timing of
     cash flows                               (599,457)   (720,947) (1,096,034)

    Standardized measure of
     discounted future net cash flows       $  931,588   1,100,676   1,454,974

<CAPTION>
                                                          Domestic
                                                         December 31,
                                               1998         1996        1995
                                                      (In Thousands)

    Future cash inflows                    $ 1,650,930   2,304,602   3,712,956
    Future costs:
     Development                               (72,215)    (83,350)    (54,064)
     Production                               (678,732)   (806,130) (1,013,750)
    Future income tax expense                  (86,412)   (269,880)   (713,182)

    Future net cash flows                      813,571   1,145,242   1,931,960
    10% discount to reflect timing of
     cash flows                               (319,889)   (481,263)   (846,174)

    Standardized measure of
     discounted future net cash flows      $   493,682     663,979   1,085,786

<CAPTION>
                                                           Canada
                                                        December 31,
                                               1998         1997        1996
                                                      (In Thousands)

    Future cash inflows                    $ 1,333,655   1,424,213   1,259,848
    Future costs:
     Development                               (40,924)    (36,927)    (36,574)
     Production                               (535,694)   (580,813)   (363,660)
    Future income tax expense                  (39,563)   (130,092)   (240,566)

    Future net cash flows                      717,474     676,381     619,048
    10% discount to reflect timing of
     cash flows                               (279,568)   (239,684)   (249,860)

    Standardized measure of
     discounted future net cash flows       $  437,906     436,697     369,188
</TABLE>

    Future cash inflows are computed by applying year-end prices
(averaging $9.89 per barrel of oil, adjusted for transportation
and other charges, $1.68 per Mcf of gas and $7.25 per barrel of
natural gas liquids at December 31, 1998) 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.  In addition to the future
gas revenues calculated at $1.68 per Mcf, Devon's total future
gas revenues also include the future tax credit payments to be
received and recorded as gas revenues pursuant to the San Juan
Basin Transaction described in Note 3.  Devon's future total and
domestic cash inflows shown in the tables above include $31
million related to these tax credit payments from 1999 through
2002.  This amount has been calculated using the assumption that
the year-end 1998 tax credit rate of $1.06 per MMBtu remains
constant.

    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.

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:
<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                                1998         1997         1996
                                                       (In Thousands)

   <S>                                       <C>           <C>          <C>
   Beginning balance                         $1,100,676    1,454,974    642,405
   Sales of oil, gas and natural gas
     liquids, net of production costs          (242,260)    (331,980)  (187,151)
   Net changes in prices and
     production costs                          (304,593)    (890,534)   763,909
   Extensions, discoveries, and improved
     recovery, net of future
     development costs                           64,614       75,698    145,310
   Purchase of reserves, net of future
     development costs                          113,655      246,173    578,099
   Development costs incurred during
     the period which reduced future
     development costs                           45,699       62,868     63,123
   Revisions of quantity estimates              (58,314)     (12,251)    35,852
   Sales of reserves in place                   (28,365)      (1,395)   (81,452)
   Accretion of discount                        134,065      198,401     73,000
   Net change in income taxes                   162,517      300,684   (456,426)
   Other, primarily changes in timing           (56,106)      (1,962)  (121,695)

   Ending balance                            $  931,588    1,100,676  1,454,974
</TABLE>

17.  Segment Information
     
     Devon manages its business by country.  As such, Devon
identifies its segments based on geographic areas.  Devon has two
reportable segments: its operations in the U.S. and its
operations in Canada.  Substantially all of both 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 1998, 1997 and 1996.  The revenues reported are all
from external customers.

<TABLE>
<CAPTION>
                                                              U.S.      Canada     Total
                                                                   (In Thousands)

As of December 31, 1998:
<S>                                                        <C>          <C>       <C>
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                                              $  70,285     73,339    143,624
   Gas sales                                                126,273     83,071    209,344
   Natural gas liquids sales                                 12,071      4,621     16,692
   Other                                                      4,095     13,753     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
</TABLE>
<TABLE>
<CAPTION>
                                                             U.S.       Canada     Total
                                                                    (In Thousands)

As of December 31, 1997:
<S>                                                       <C>          <C>        <C>
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
</TABLE>

<TABLE>
<CAPTION>
                                                             U.S.      Canada      Total
                                                                   (In Thousands)

As of December 31, 1996:
<S>                                                       <C>          <C>        <C>
Current assets                                            $ 42,677     190,966    233,643
Property and equipment, net of accumulated depreciation,
  depletion and amortization                               632,839     286,708    919,547
Other assets                                                10,031      20,069     30,100

     Total assets                                         $685,547     497,743  1,183,290

Current liabilities                                         23,389     123,418    146,807
Long-term debt                                               8,000      75,000     83,000
Deferred tax liabilities                                    73,821      33,182    107,003
Other liabilities                                           11,585       6,623     18,208
TCP Securities                                             149,500           -    149,500
Stockholders' equity                                       419,252     259,520    678,772

     Total liabilities and stockholders' equity           $685,547     497,743  1,183,290

Year ended December 31, 1996:
Revenues
   Oil sales                                              $ 80,142      55,881    136,023
   Gas sales                                                68,049      33,394    101,443
   Natural gas liquids sales                                14,367       4,932     19,299
   Other                                                     1,459      33,111     34,570

     Total revenues                                        164,017     127,318    291,335

Costs and expenses
   Lease operating expenses                                 31,568      27,166     58,734
   Production taxes                                         10,658         222     10,880
   Depreciation, depletion and amortization                 43,361      26,946     70,307
   General and administrative expenses                       9,101       6,010     15,111
   Interest expense                                          5,277       7,385     12,662
   Deferred effect of changes in foreign currency exchange
     rate on subsidiary's long-term debt                         -         199        199
   Distributions on preferred securities of subsidiary 
     trust                                                   4,753           -      4,753

     Total costs and expenses                              104,718      67,928    172,646

Earnings before income tax expense                          59,299      59,390    118,689

Income tax expense
   Current                                                   6,709       1,125      7,834
   Deferred                                                 17,789      25,463     43,252

     Total income tax expense                               24,498      26,588     51,086

Net earnings                                             $  34,801      32,802     67,603

Capital expenditures                                     $  98,855     169,822    268,677
</TABLE>

18.  Supplemental Quarterly Financial Information (Unaudited)

     Following is a summary of the unaudited interim results of
operations for the years ended December 31, 1998 and 1997.  The
following amounts have been restated to reflect the Northstar
Combination, and are therefore different from the results
previously reported.
<TABLE>
<CAPTION>
                                                            1998
                                     First      Second      Third     Fourth      Full
                                    Quarter     Quarter    Quarter    Quarter     Year
                                         (In Thousands, Except Per Share Amounts)

Oil, gas and natural gas liquids
 <S>                               <C>           <C>        <C>        <C>       <C>
 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 share:
 Basic                                $0.29        0.25      (1.72)     (0.07)     (1.25)
 Diluted                              $0.29        0.25      (1.72)     (0.07)     (1.25)

<CAPTION>
                                                            1997
                                     First      Second      Third      Fourth      Full
                                    Quarter     Quarter    Quarter     Quarter     Year
                                        (In Thousands, Except Per Share Amounts)

Oil, gas and natural gas liquids
 <S>                               <C>          <C>        <C>         <C>       <C>
 sales                             $103,236     106,413    114,009     128,446   452,104
Total revenues                     $133,882     113,114    119,400     133,263   499,659
Net earnings (loss)                $ 42,652      14,604     16,785    (374,032) (299,991)
Net earnings (loss) per share:
 Basic                                $0.99        0.30       0.35       (7.75)    (6.38)
 Diluted                              $0.91        0.30       0.34       (7.75)    (6.38)
</TABLE>

     The fourth quarter of 1997 includes a $625.5 million pre-tax
reduction of the carrying value of Canadian oil and gas
properties.  The after-tax effect of this charge was $397.9
million, or $8.24 per share.  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.

<PAGE>

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 30, 1999.

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 30, 1999.

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 30, 1999.

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 30, 1999.
                            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 49 of this report.

          2.   Consolidated Financial Statement Schedules

                    All financial statement schedules are omitted
               as they are inapplicable, or the required
               information is immaterial.

          3.   Exhibits

               2.1  Agreement and Plan of Merger among Registrant, Devon Energy
                    Corporation (Nevada), Kerr-McGee Corporation, Kerr-McGee 
                    North American Onshore Corporation and Kerr-McGee Canada 
                    Onshore Ltd., dated October 17, 1996 (incorporated by 
                    reference to Addendum A to Registrant's definitive proxy
                    statement for a special meeting of shareholders, filed 
                    on November 6, 1996).
               
               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 Amended and
                    Restated Certificate of Incorporation
                    (incorporated by reference to Exhibit 3 to
                    Registrant's Form 8-K dated as of December
                    11, 1998).

               3.2  Registrant's Bylaws
                    (incorporated by reference to Exhibit 3.2 to
                    Registrant's Registration Statement on Form 8-
                    B filed on June 7, 1995).

               4.1  Form of Common Stock
                    Certificate (incorporated by reference to
                    Exhibit 4.1 to Registrant's Registration
                    Statement on Form 8-B filed on June 7, 1995).

               4.2  Rights Agreement between
                    Registrant and The First National Bank of
                    Boston (incorporated by reference to Exhibit
                    4.2 to Registrant's Registration Statement on
                    Form 8-B filed on June 7, 1995).

               4.3  First Amendment to Rights
                    Agreement between Registrant and The First
                    National Bank of Boston, dated October 16,
                    1996 (incorporated by reference to Exhibit H-
                    1 to Addendum A to Registrant's definitive
                    proxy statement for a special meeting of
                    shareholders, filed on November 6, 1996).

               4.4  Second Amendment to Rights Agreement between Registrant and
                    the First National Bank of Boston, dated December 31, 1996
                    (incorporated by reference to Exhibit 4.2 to Registrant's 
                    Current Report on Form 8-K dated December 31, 1996).
               
               4.5  Third Amendment to Rights Agreement between Registrant and
                    The First National Bank of Boston, dated December 10, 1998.

               4.6  Certificate of Designations of
                    Series A Junior Participating Preferred Stock
                    of Registrant (incorporated by reference to
                    Exhibit 3.3 to Registrant's Registration
                    Statement on Form 8-B filed on June 7, 1995).

               4.7  Certificate of Trust of Devon
                    Financing Trust [incorporated by reference to
                    Exhibit 4.5 to Amendment No. 1 to
                    Registrant's Registration Statement on Form S-
                    3 (No. 333-00815)].

               4.8  Amended and Restated Declaration of Trust of Devon Financing
                    Trust, dated as of July 3, 1996, by J. Larry Nichols,
                    H. Allen Turner, William T. Vaughn, The Bank of New 
                    York (Delaware) and The Bank of New York as Trustees 
                    and the Registrant as Sponsor [incorporated by reference
                    to Exhibit 4.6 to Amendment No. 1 to Registrant's 
                    Registration Statement on Form S-3 (No. 333-00815)].
               
               4.9  Indenture,
                    dated as of July 3, 1996, between the
                    Registrant and The Bank of New York
                    [incorporated by reference to Exhibit 4.7 to
                    Amendment No. 1 to Registrant's Registration
                    Statement on Form S-3 (No. 333-00815)].
               
               4.10 First Supplemental Indenture, dated as of
                    July 3, 1996, between the Registrant and The
                    Bank of New York [incorporated by reference
                    to Exhibit 4.8 to Amendment No. 1 to
                    Registrant's Registration Statement on Form S-
                    3 (No. 333-00815)].

               4.11 Form of 6 1/2% Preferred
                    Convertible Securities (included as Exhibit A-
                    1 to Exhibit 4.7 above).

               4.12 Form of 6 1/2% Convertible
                    Junior Subordinated Debentures (included as
                    Exhibit B to Exhibit 4.7 above).

               4.13 Preferred Securities Guarantee
                    Agreement, dated July 3, 1996, between
                    Registrant, as Guarantor, and The Bank of New
                    York, as Preferred Guarantee Trustee
                    [incorporated by reference to Exhibit 4.11 to
                    Amendment No. 1 to Registrant's Registration
                    Statement on Form S-3 (No. 333-00815)].

               4.14 Stock Rights and Restrictions
                    Agreement, dated as of December 31, 1996,
                    between Registrant and Kerr-McGee Corporation
                    (incorporated by reference to Exhibit 4.3 to
                    Registrant's Current Report on Form 8-K dated
                    December 31, 1996).

               4.15 Registration Rights Agreement, dated December 31, 1996, by
                    and between Registrant and Kerr-McGee Corporation 
                    (incorporated by reference to Exhibit 4.4 to 
                    Registrant's Current Report on Form 8-K, dated 
                    December 31, 1996).
               
               4.16 Support Agreement, dated
                    December 10, 1998, between the Registrant and
                    Northstar Energy Corporation (incorporated by
                    reference to Exhibit 4.1 to Registrant's Form
                    8-K dated as of December 11, 1998).

               4.17 Exchangeable Share Provisions (incorporated by reference to
                    Exhibit 4.2 to Registrant's Form 8-K dated as of 
                    December 11, 1998).
               
               9    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
                    Registrant's Form 8-K dated as of December
                    11, 1998).

               10.1 U.S. Credit Agreement, dated December 11, 1998, among the
                    Registrant, as U.S. Borrower, NationsBank, N.A., as
                    Administrative Agent, NationsBanc Montgomery Securities,
                    L.L.C., as Arranger, Bank One, Texas, N.A., as 
                    Syndication Agent, Bank of Montreal, as Documentation 
                    Agent, First Union, as Co-Documentation Agent, and
                    Certain Financial Institutions, as
                    Lenders (incorporated by reference to Exhibit 10.1 to
                    Registrant's Form 8-K dated as of December 11, 1998).
               
               10.2 Canadian Credit Agreement, dated December 11, 1998, among
                    Northstar Energy Corporation and Devon Energy Canada 
                    Corporation, as Canadian Borrowers, Bank of America Canada,
                    as Administrative Agent, NationsBanc Montgomery Securities, 
                    L.L.C., as Arranger, First Chicago Capital Markets, Inc., as
                    Syndication Agent, Bank of Montreal, as Documentation
                    Agent, First Union, as Co-Documentation Agent, and 
                    Certain Financial Institutions, as Lenders (incorporated
                    by reference to Exhibit 10.2 to Registrant's Form 8-K 
                    dated as of December 11, 1998).

               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.

               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 Devon Energy Corporation 1988 Stock Option Plan
                    [incorporated by reference to Exhibit 10.4 to Registrant's
                    Registration Statement on Form S-4 (No. 33-23564)].*

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

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

               10.8 Severance Agreement between
                    Devon Energy Corporation (Nevada), Devon
                    Energy Corporation (Delaware) and Mr. J.
                    Larry Nichols, dated December 3, 1992
                    (incorporated by reference to Exhibit 10.10
                    to Registrant's Amendment No. 1 to Annual
                    Report on Form 10-K for the year ended
                    December 31, 1992).*

               10.9 Severance Agreement between
                    Devon Energy Corporation (Nevada), Devon
                    Energy Corporation (Delaware) and Mr. J.
                    Michael Lacey, dated December 3, 1992
                    (incorporated by reference to Exhibit 10.12
                    to Registrant's Amendment No. 1 to Annual
                    Report on Form 10-K for the year ended
                    December 31, 1992).*

              10.10 Severance Agreement
                    between Devon Energy Corporation (Nevada),
                    Devon Energy Corporation (Delaware) and Mr.
                    H. Allen Turner, dated December 3, 1992
                    (incorporated by reference to Exhibit 10.13
                    to Registrant's Amendment No. 1 to Annual
                    Report on Form 10-K for the year ended
                    December 31, 1992).*
 
              10.11 Severance Agreement
                    between Devon Energy Corporation (Nevada),
                    Devon Energy Corporation (Delaware) and Mr.
                    Darryl G. Smette, dated December 3, 1992
                    (incorporated by reference to Exhibit 10.14
                    to Registrant's Amendment No. 1 to Annual
                    Report on Form 10-K for the year ended
                    December 31, 1992).*

              10.12 Severance Agreement
                    between Devon Energy Corporation (Nevada),
                    Registrant and Duke R. Ligon, dated March 26,
                    1997 (incorporated by reference to Exhibit
                    10.11 to Registrant's Quarterly Report on
                    Form 10-Q for the quarter ended June 30,
                    1997).*
 
              10.13 Employment Agreement between Devon Energy Corporation
                    (Nevada), Registrant and Duke R. Ligon, dated February 7,
                    1997 (incorporated by reference to Exhibit 10.12 to 
                    Registrant's Quarterly Report on Form 10-Q for the
                    quarter ended June 30, 1997).*
               
              10.14 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 Registrant's Quarterly Report on Form 10-Q for 
                    the quarter ended June 30, 1997).*
               
              10.15 Supplemental Benefit Agreement between Northstar Enerty
                    Corporation and John A. Hagg dated February 17, 1999.*
               
              10.16 Consulting Agreement between Registrant and Thomas F.
                    Ferguson dated June 1, 1989.

              10.17 Sale and Purchase
                    Agreement relating to Registrant's San Juan
                    Basin gas properties (incorporated by
                    reference to Exhibit 10.15 to Registrant's
                    Quarterly Report on Form 10-Q for the quarter
                    ended September 30, 1995).

              10.18 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 Registrant's
                    Quarterly Report on Form 10-Q for the quarter
                    ended September 30, 1995).
             
              10.19 Registration Rights Agreement,
                    dated July 3, 1996, by and among the
                    Registrant, Devon Financing Trust and Morgan
                    Stanley & Co. Incorporated [incorporated by
                    reference to Exhibit 10.1 to Amendment No. 1
                    to Registrant's Registration Statement on
                    Form S-3 (No. 333-00815)].
             
              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 Deloitte & Touche LLP

              23.6  Consent of PricewaterhouseCoopers LLP

              * Compensatory plans or arrangements.

          (b)      Reports on Form 8-K - A Current Report on Form
          8-K dated December 11, 1999, was filed by the
          Registrant announcing the completion of the Northstar
          Combination. A Current Report on Form 8-K dated January
          28, 1999, was filed by the Registrant regarding year-
          end 1998 financial results and year-end oil and gas
          reserves.  A Current Report on Form 8-K dated February
          8, 1999, was filed by the Registrant regarding 1999
          forward-looking information.  A Current Report on Form
          8-K dated February 22, 1999 was filed regarding
          January, 1999 financial results.

<PAGE>
                           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 29, 1999                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 29, 1999                By   /s/ John W. Nichols
                              John W. Nichols
                              Chairman of the Board and Director


March 29, 1999                By   /s/ J. Larry Nichols
                              J. Larry Nichols
                              President, Chief Executive Officer
and Director


March 29, 1999                By   /s/ William T. Vaughn
                              William T. Vaughn
                              Vice President - Finance


March 29, 1999                By   /s/ Danny J. Heatly
                              Danny J. Heatly
                              Controller


March 29, 1999                By   /s/ H. R. Sanders, Jr.
                              H. R. Sanders, Jr.
                              Director





March 29, 1999                By   /s/ Luke R. Corbett
                              Luke R. Corbett, Director



March 29, 1999                By   /s/ Thomas F. Ferguson
                              Thomas F. Ferguson, Director



March 29, 1999                By   /s/ David M. Gavrin
                              David M. Gavrin, Director



March 29, 1999                By   /s/ Michael E. Gellert
                              Michael E. Gellert, Director



March 29, 1999                By   /s/ John A. Hagg
                              John A. Hagg, Director



March 29, 1999                By   /s/ Michael M. Kanovsky
                              Michael M. Kanovsky, Director



March 29, 1999                By   /s/ Tom J. McDaniel
                              Tom J. McDaniel, Director



March 29, 1999                By   /s/ Lawrence H. Towell
                              Lawrence H. Towell, Director

<PAGE>
                        INDEX TO EXHIBITS

Exhibit                                                               Page

  2.1  Agreement and Plan of Merger among Registrant, Devon Energy
          Corporation (Nevada), Kerr-McGee Corporation, Kerr-McGee North
          American Onshore Corporation and Kerr-McGee Canada Onshore Ltd.,
          dated October 17, 1996                                            *
  
  2.2  Amended and Restated Combination Agreement between the Registrant and
          Northstar Energy Corporation dated as of June 29, 1998            *

  3.1  Registrant's Amended and Restated Certificate of
          Incorporation                                                     *

  3.2  Registrant's Bylaws                                                  *

  4.1  Form of Common Stock Certificate                                     *

  4.2  Rights Agreement between Registrant and The First National
          Bank of Boston                                                    *

  4.3  First Amendment to Rights Agreement between Registrant and
          The First National Bank of Boston, dated October 16, 1996         *

  4.4  Second Amendment to Rights Agreement between Registrant and
          the First National Bank of Boston, dated December 31, 1996        *

  4.5  Third Amendment to Rights Agreement between Registrant and
          The First National Bank of Boston, dated December 10, 1998.     117

  4.6  Certificate of Designations of Series A Junior Participating
          Preferred Stock of Registrant                                     *

  4.7  Certificate of Trust of Devon Financing Trust                        *

  4.8  Amended and Restated Declaration of Trust of Devon Financing
          Trust, dated as of July 3, 1996, by J. Larry Nichols, H. Allen
          Turner, William T. Vaughn, The Bank of New York (Delaware) and
          The Bank of New York as Trustees and the Registrant as Sponsor    *

  4.9  Indenture, dated as of July 3, 1996, between the Registrant
          and The Bank of New York                                          *

  4.10  First Supplemental Indenture, dated as of July 3, 1996,
          between the Registrant and The Bank of New York                   *

  4.11  Form of 6 1/2% Preferred Convertible Securities                     *

  4.12  Form of 6 1/2% Convertible Junior Subordinated Debentures           *

  4.13  Preferred Securities Guarantee Agreement, dated July 3,
          1996, between Registrant, as Guarantor, and The Bank of New York,
          as Preferred Guarantee Trustee                                    *

  4.14  Stock Rights and Restrictions Agreement, dated as of
          December 31, 1996, between Registrant and Kerr-McGee Corporation  *

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

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

  4.17  Exchangeable Share Provisions                                       *

  9     Voting and Exchange Trust Agreement, dated December 10, 1998, by and
          between the Registrant, Northstar Energy Corporation and CIBC 
          Mellon Trust Company                                              *
  
  10.1  U.S. Credit Agreement, dated December 11, 1998, among the
          Registrant, as U.S. Borrower, NationsBank, N.A., as
          Administrative Agent, NationsBanc Montgomery Securities, L.L.C.,
          as Arranger, Bank One, Texas, N.A., as Syndication Agent, Bank of
          Montreal, as Documentation Agent, First Union, as Co-
          Documentation Agent, and Certain Financial Institutions, as
          Lenders                                                           *

  10.2  Canadian Credit Agreement, dated December 11, 1998, among
          Northstar Energy Corporation and Devon Energy Canada Corporation,
          as Canadian Borrowers, Bank of America Canada, as Administrative
          Agent, NationsBanc Montgomery Securities, L.L.C., as Arranger,
          First Chicago Capital Markets, Inc., as Syndication Agent, Bank
          of Montreal, as Documentation Agent, First Union, 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      119

  10.4  Northstar Energy Corporation U.S. $150,000,000 6.79% Senior
          Notes Due 2009 Note Agreement Dated as of March 2, 1998         176

  10.5  Devon Energy Corporation 1988 Stock Option Plan                     *

  10.6  Devon Energy Corporation 1993 Stock Option Plan                     *

  10.7  Devon Energy Corporation 1997 Stock Option Plan                     *

  10.8  Severance Agreement between Devon Energy Corporation
          (Nevada), Devon Energy Corporation (Delaware) and Mr. J. Larry
          Nichols, dated December 3, 1992                                   *

  10.9  Severance Agreement between Devon Energy Corporation
          (Nevada), Devon Energy Corporation (Delaware) and Mr. J. Michael
          Lacey, dated December 3, 1992                                     *

  10.10 Severance Agreement between Devon Energy Corporation
          (Nevada), Devon Energy Corporation (Delaware) and Mr. H. Allen
          Turner, dated December 3, 1992                                    *

  10.11 Severance Agreement between Devon Energy Corporation
          (Nevada), Devon Energy Corporation (Delaware) and Mr. Darryl G.
          Smette, dated December 3, 1992                                    *

  10.12 Severance Agreement between Devon Energy Corporation
          (Nevada), Registrant and Duke R. Ligon, dated March 26, 1997      *

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

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

  10.15 Supplemental Benefit Agreement between Northstar Energy
          Corporation and John A. Hagg dated February 17, 1999            255

  10.16 Consulting Agreement between Registrant and Thomas F.
          Ferguson dated June 1, 1989                                     260

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

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

  10.19 Registration Rights Agreement, dated July 3, 1996, by
          and among the Registrant, Devon Financing Trust and Morgan
          Stanley & Co.                                                     *

   12   Computation of ratio of earnings to fixed charges                 262

   21   Subsidiaries of Registrant                                        263

  23.1  Consent of LaRoche Petroleum Consultants, Ltd.                    264

  23.2  Consent of AMH Group Ltd.                                         265

  23.3  Consent of Paddock Lindstrom & Associates Ltd.                    266

  23.4  Consent of KPMG LLP                                               267

  23.5  Consent of Deloitte & Touche LLP                                  268

  23.6  Consent of PricewaterhouseCoopers LLP                             269