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, 1997
                                 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 February  24, 1998, was $719,015,211.   At such 
date 32,318,895 shares of common stock were outstanding.

              DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 1998 annual meeting of stockholders -  Part III

<PAGE>

                         TABLE OF CONTENTS



                                                             Page
PART I

 Item 1. Business                                              4
 Item 2. Properties                                           12
 Item 3. Legal Proceedings                                    21
 Item  4.  Submission of Matters to a Vote of
   Security  Holders                                          21

PART II
 Item 5. Market for Registrant's Common Equity
   and Related Stockholder Matters                            22
 Item 6. Selected Financial Data                              23
 Item  7. Management's  Discussion and  Analysis
   of Financial Condition and Results of Operations           25
 Item 8. Financial Statements and Supplementary Data          43
 Item 9. Changes in  and Disagreements  with
   Accountants on Accounting
   and Financial Disclosure                                   86

PART III
 Item 10. Directors and Executive Officers of the 
   Registrant                                                 86
 Item 11. Executive Compensation                              86
 Item 12. Security Ownership of Certain Beneficial
   Owners and Management                                      86
 Item 13.  Certain  Relationships  and  Related
   Transactions                                               86

PART IV
 Item 14. Exhibits, Financial Statement Schedules,
   and Reports on Form 8-K                                    86

                           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 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", "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 ("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.   The  principal and administrative offices
of Devon are located at 20 North Broadway, Suite  1500, Oklahoma City, 
OK 73102-8260  (telephone  405/2353611).

      Devon  currently owns interests in approximately 1,700 oil and
gas  properties concentrated in five operating  areas:  the Permian Basin
in southeastern New Mexico and western Texas;  the San  Juan  Basin
in northwestern New Mexico; the Rocky  Mountain region in Wyoming; 
the Mid-continent region in Oklahoma and the Texas Panhandle;
and the Western Canada Sedimentary Basin in Alberta, Canada.  
(A  detailed description of the significant properties can be found under
"Item 2. Properties -  Significant Properties" beginning on page 17 hereof.)

     At December 31, 1997, Devon's estimated proved reserves were 184.0 
MMBoe, which were relatively balanced between oil and NGLs (44%) and 
natural gas (56%).  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 $913 million.  Devon is one
of the top 20 public independent  oil and  gas companies in the 
United States, as measured by oil and gas reserves.

Strategy

      Devon's  primary  objectives are to build production,  cash flow  
and  earnings  per  share by: (a)  acquiring  oil  and  gas properties,  
(b) exploring for new oil and gas reserves  and  (c) optimizing production 
from existing oil and gas properties.

      During 1988, Devon expanded its capital base with its first 
issuance of common stock to the public.  This transaction began a 
substantial expansion program, which has continued  through  the subsequent
nine  years.  Devon has  used  a  two-pronged  growth strategy  of  
acquiring  producing properties and engaging in drilling activities.

      In  the  last  five  years alone, Devon has consummated 5 
significant acquisitions and drilled 873 new wells, 842 of  which were
producers. These activities have resulted in net reserve additions
(i.e.,  extensions,  discoveries,  purchases and revisions)  of 189.5 MMBoe. 
Capital costs incurred to  complete these  activities totaled $736.8
million, for a five-year finding and  development cost of $3.89 per Boe.
Net  reserve  additions divided  by  production,  resulted in an annual
average  reserve replacement factor of 320%.

      Devon's objective, however, is to increase value per share, not
simply to increase total assets.  Reserves have grown from 2.94 Boe per
diluted share at year-end 1992 to 4.91 Boe per diluted share at year-end 
1997.  During this same  five-year period, net  debt (long-term debt
minus  working  capital)  has remained relatively low, never exceeding
$1.17 per Boe.  In fact, at year-end 1997, the Company had no debt and 
had working capital of $0.34 per Boe.

      The  oil  and  gas  industry is characterized by volatile product 
prices.  Devon's management believes that 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, Devon's profitability will 
be maximized, even during periods of low oil and/or gas prices.  In
addition, Devon remains financially flexible to take advantage of
opportunities  for mergers, acquisitions, exploration or other growth
opportunities.  

Recent Developments

      On  February 13, 1998, the Company commenced a tender offer 
(the "Offer") for any and all of the units of beneficial interest 
("Units") of Burlington Resources Coal Seam Gas  Royalty  Trust 
(the  "Trust").   The  Offer of $8.75 per Unit  in cash is not conditioned
on the tender of any minimum or maximum  number  of Units.  The  initial
expiration of the Offer is expected to  be  March 13, 1998.

      If  all  of the Trust's Units are tendered, the transaction would
have  a  total value of approximately $80 million.   Devon anticipates 
using its cash on hand and committed credit lines  to fund the transaction.

      As  of  February 24, 1998, results of the Offer  were  not known, 
and no estimate could be made as to how many Units of the Trust will be 
acquired, if any.  Devon intends to hold any Units it  acquires
in the Offer for investment purposes.   The  Trust holds  certain  
economic interests in the Northeast Blanco  Unit ("NEBU") of northwest 
New Mexico.  Devon is the operator  of  and owns  a significant reserve
position in this property.  See "Item 2   Properties.  Significant  
Properties  -  San  Juan  Basin Northeast Blanco Unit."

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.  The  majority of Devon's drilling
operations in 1998 will be concentrated in the Permian Basin,  the 
Rocky Mountains, the Texas Panhandle and Gulf Coast regions of the U.S.
and in the Western Canada Sedimentary  Basin of Alberta, Canada.

      The following tables set forth Devon's drilling results for the 
past five years.  
<TABLE>
<CAPTION>
                         Development Wells
               Gross (1)                   Net (2)

        Productive  Dry  Total    Productive   Dry    Total
                          
<C>        <C>      <C>   <C>       <C>       <C>    <C>
1993        92       4     96        43.39    1.40    44.79
1994        77       1     78        44.40    0.28    44.68
1995       184       3    187       143.87    0.29   144.16
1996       188       3    191       137.05    0.95   138.00
1997(3)    268       9    277       119.20    4.90   124.10

           809      20    829       487.91    7.82   495.73
</TABLE>
<TABLE>
<CAPTION>
                         Exploratory Wells
               Gross (1)                    Net (2)

       Productive   Dry  Total     Productive   Dry    Total
                          
<C>        <C>      <C>   <C>       <C>        <C>     <C>
1993        4        2     6         2.05      0.49     2.54
1994        2        3     5         0.52      2.37     2.89
1995        9        3    12         2.53      1.18     3.71
1996        2        1     3         1.50      0.08     1.58
1997(3)    16        2    18         6.10      1.50     7.60

           33       11    44        12.70      5.62    18.32


(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.
(3)  Included  in  the  1997 figures  are  24  gross
     (10.2  net) productive development wells and 2 gross
     (1.1  net)  productive exploratory wells drilled in
     Canada.  Devon drilled no dry  holes in  Canada.
     Devon had no Canadian properties prior to  December 31, 1996.
</TABLE>

      As  of  December 31, 1997, Devon was participating in the 
drilling of 54 gross (17.6 net) wells, which are not included 
in the  table above. All such wells were being drilled in the
United States.  Through February 24, 1998, 15 gross (10.1 net)
wells had been completed as productive.  The remaining  were  still
in process.

Customers

     For the years ended December 31, 1997 and December 31, 1996, 
one  significant  purchaser, Aquila Energy Marketing Corporation 
("Aquila"), accounted for 46% and 45%, respectively, of Devon's
natural gas sales or 22% and 19%, respectively, of total revenue. 
For the year ended December 31, 1995, two significant purchasers, 
Aquila and Enron Gas Marketing, Inc. ("Enron"), accounted for 31% and
16%, respectively, of Devon's gas sales or 14% and 7%, respectively, 
of total revenue.  Aquila and Enron purchase gas from numerous Devon 
properties, at variable and market-sensitive prices.  Devon does
not consider itself dependent upon any one of these purchasers, since
other purchasers are willing to purchase this same gas production at 
competitive prices.

      Devon  sells its remaining 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.


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.

      Natural Gas Marketing.  A large portion of Devon's natural gas
production is sold at variable or market-sensitive prices. Though exact
percentages vary daily, as of December 31, 1997, approximately  73% of 
such natural gas is sold under short-term contracts.  The remaining 27% 
of Devon's natural gas is marketed under various long-term contracts
(one year or more) which dedicate the natural gas to a purchaser for an
extended period of time, but which still may involve variable and 
market-sensitive pricing.

      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. These
market-sensitive sales are referred to as  "spot market"  sales.  The 
spot market has become progressively more competitive in recent years.
As a result, prices on the spot market have been volatile. From time to 
time Devon has withheld gas from the market due to low prices.

     Physical Delivery Contracts.  As of February 24, 1998, Devon had
made firm commitments to sell an average of approximately 30% of its
estimated 1998 coal seam gas production (or approximately 9% of
total estimated 1998 gas production) at a fixed price of approximately
$1.45  per  Mcf, which equates to a price of approximately $2.04 per MMBtu.
(The $1.45 per Mcf price includes the effect of adjusting for Btu content
and is net of costs for transportation and removing carbon dioxide.  This
price excludes the expected benefit of the San Juan Basin Transaction. 
See "Item 2.  Properties - Significant Properties - San Juan Basin
San Juan Basin Transaction").  Devon has also made other firm commitments
to  sell certain quantities of its 1998 domestic conventional and Canadian
gas production at fixed  prices. However, such other commitments are
not material.
                                                                    
     If  Devon  is  unable  to produce the volumes required to fulfill
its firm commitments, Devon would have to purchase gas on the open
market to satisfy such commitments.  During the past five years, Devon
has satisfied all of its firm commitments from its production and 
anticipates that it will continue to do so in the future.

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 which 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 1997 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 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 of Canada has legislation
and regulations governing land tenure, royalties, production rates and
taxes, environmental protection and other matters.  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 of 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.
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 form  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 and the government
of Canada.  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 and
the government of Canada.  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 1997 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, 1997, Devon's staff consisted of 383 fulltime
employees, including 32 professionals in engineering, 16 in geology,
21 in the land department, 9 in oil and gas  marketing, 53 in accounting
and data processing, 21 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 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, 1997. 
Approximately  92% of Devon's  domestic proved reserves were estimated by
LaRoche Petroleum  Consultants,  Ltd.,  independent petroleum  engineers
("LaRoche").  The  remainder of such reserves were  estimated by Devon's
internal staff of engineers. All of the Canadian  proved reserves were 
calculated by the independent petroleum consultants, AMH Group Ltd. ("AMH"). 
In preparing its estimates, Devon's  staff  used standard geological and 
engineering  methods generally accepted by the petroleum industry and in
accordance with  SEC  guidelines (as described in the notes below).
LaRoche and AMH indicated in their reports that they also used standard
geological and engineering methods generally accepted by the petroleum
industry and in accordance with SEC guidelines.   These estimates
correspond with the method used in presenting the supplemental information 
on oil and gas operations in note 14 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.  Please refer to the supplemental information on oil
and gas operations in note 14 to Devon's consolidated financial statements
(included herein) for a presentation of reserves separated between Canada
and the U.S.
<TABLE>
<CAPTION>
                                   Total        Proved          Proved
                                  Proved      Developed     Undeveloped
                                Reserves     Reserves (1)   Reserves (2)
                                                               
  <S>                          <C>            <C>              <C>
  Oil (MBbls)                     68,443         60,165          8,278          
  Gas (MMcf)                     616,004        506,374        109,630
  NGLs (MBbl)                     12,881         12,098            783                 
  MBoe (3)                       183,991        156,658         27,333
  Pre-tax Future Net Revenue   1,562,022      1,390,359        171,663 
    ($ thousands) (4)       
  Pre-tax 10% Present Value      913,073        841,036         72,037
    ($ 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, 1997. 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 $16.93 per
   Bbl of  oil, $1.89  per  Mcf  of  natural gas ($1.94
   per Mcf  including  the effect  of the San Juan Basin
   Transaction), and $12.42 per  Bbl of  NGLs.  These
   prices compare to December 31, 1997, benchmark posted
   prices  of  $15.50 per Bbl for West Texas
   Intermediate crude  oil  and a composite of $2.34 per
   MMBtu for  Texas  Gulf Coast  spot gas, representing
   prices paid 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 which Devon operates and to exclude all 
interests in wells which 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, 1997. 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.

      The  following table presents the net quantities
of Devon's oil, natural gas and NGL reserves as of the end of
the  years indicated.   Approximately 95%, 91%, 92%,
94% and 92% of  Devon's domestic reserves as of the
years ended December 31, 1993, 1994, 1995, 1996 and
1997, respectively, were estimated  by  LaRoche. The
balance  of the domestic reserves was estimated by
Devon's internal staff of engineers.  All of the
Canadian reserves as  of the  years  ended December 31, 1996
and 1997, were estimated  by AMH.  (Devon had no Canadian reserves
prior to 1996.)

<TABLE>
<CAPTION>
                                 Total Proved Reserves

As of December 31,       Oil (MBbls)     Gas (MMcf)    NGLs(MBbls)    Total (Mboe)

 <S>                        <C>            <C>            <C>           <C>
 1993                       14,897         369,254        1,854          78,293      
 1994                       42,165         347,560        5,442         105,534
 1995                       44,466         363,846        9,469         114,576
 1996                       67,481         595,519       12,579         179,313
 1997                       68,443         616,004       12,881         183,991
</TABLE>

                               Proved Developed Reserves
<TABLE>
<CAPTION>
As  of  December 31,     Oil (MBbls)     Gas (MMcf)    NGLs(MBbls)     Total (MBoe)

 <S>                        <C>            <C>           <C>             <C>
 1993                       11,548         355,536        1,751           72,555
 1994                       18,718         324,302        3,123           75,891
 1995                       28,703         311,664        6,149           86,796
 1996                       60,202         570,265       11,212          166,458
 1997                       60,165         506,374       12,098          156,659
</TABLE>

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, 1997, is  set  forth  in "Item  7.
Management's  Discussion  and  Analysis  of  Financial
Condition and Results of Operations."

Well Statistics

        As  of  December  31,  1997,  Devon  held interests in 
approximately  1700  properties.   The following table depicts Devon's
interests in producing wells located on these properties:

<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.       8,427    1,230      2,852     703       11,279   1,933
Canada        692      117        234      61          926     178
Total       9,119    1,347      3,086     764       12,205   2,111

<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, 1997.

<TABLE>
<CAPTION>
                          Developed              Undeveloped 
                    Gross(1)    Net(2)       Gross(1)     Net(2)
                              
    <S>           <C>          <C>         <C>           <C>
    Alabama           4,662      2,247           583         261
    Arkansas          5,906        589        14,649       3,627
    Colorado          6,348      2,581        22,319       9,519
    Kansas           20,036      8,693         6,433         713
    Louisiana        12,840      5,047        12,680       5,769
    Mississippi       8,291        548         4,148       1,206
    Montana          16,326        365        11,891       1,779
    Nebraska            160         80         6,517       1,377
    New Mexico      145,481     61,199       237,695      79,953
    North Dakota      9,427      3,506        11,453       2,355
    Oklahoma        278,720     85,017       212,230      48,160
    South Dakota      6,051        149           162          78
    Texas           858,224    228,070       608,034     184,955
    Utah              5,305        864         2,200       2,200
    Wyoming         195,067     82,078       135,265      76,361
    Total U. S.   1,572,844    481,033     1,286,259     418,313
    Canada          187,621     76,200       113,663      75,732
    Grand Total   1,760,465    557,233     1,399,922     494,045

<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 is 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 2,133 of its 12,205 wells. These
operated  wells  account for approximately 57% 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, 1997.
<TABLE>
<CAPTION>
                                                                       10% Presents
                                                                        Value (3)   10% Present
                     Oil(MBbls) Gas(MMcf) NGLs(MBbl) MBoe(1) MBoe% (2)  ($000)       Value% (4)
<S>                   <C>        <C>       <C>      <C>      <C>       <C>           <C>
Permian Basin:
West Texas and
Southeast New Mexico
  Grayburg-Jackson                                     
    Field             19,296      1,539     1,539    21,864   11.9%    $101,060       11.1%    
  Ozona Field            247     50,476     2,553    11,213    6.1%      51,531        5.6%          
  Other               22,061     74,068     3,199    37,605   20.4%     191,797       21.0%
  Total               41,604    130,718     7,291    70,682   38.4%    $344,388       37.7%        

San Juan Basin:
Northwest New Mexico
  Northeast Blanco                                                                                
    Unit                   4     148,699       40    24,827   13.5%     $120,881 (5)  13.2%     
  32-9 Unit                0      80,502        0    13,417    7.3%       60,717 (6)   6.7%
  Other                    3         280       10        60    0.0%          162       0.0%
  Total                    7     229,481       50    38,304   20.8%     $181,760      19.9%

Rocky Mountains:
Colorado and Wyoming
  House Creek         11,656         675        0    11,768    6.4%     $43,266        4.7%
  Other                5,217      86,570    2,953    22,598   12.3%     106,470       11.7%
  Total               16,873      87,245    2,953    34,366   18.7%    $149,736       16.4%

Mid-Continent:
Oklahoma and
Texas Panhandle        2,119     112,815    1,778    22,699   12.3%    $134,360       14.7%

Canada                 7,541      48,180      809    16,380    8.9%     $92,625 (7)   10.2%

All Other Properties     299       7,565        0     1,560    0.9%     $10,204        1.1%                 

Grand Total           68,443     616,004   12,881   183,991  100.0%    $913,073      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 $17.6 million of additional value
    attributable  to the San Juan Basin Transaction
    through the year 2002.
(6) Includes $11.1 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: $0.6992 U. S.
</TABLE>

      Permian  Basin Properties.  The Permian Basin is a prolific oil
and gas producing province 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 wellsituated leasehold position continues to provide 
Devon with numerous exploration and development opportunities.  Devon 
has also initiated enhanced oil recovery projects to further expand reserves.

      Grayburg-Jackson Field. Devon acquired the Grayburg-Jackson 
Field in 1994. The property consists of approximately 8,500 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 onethird of Devon's 
proved oil reserves and is Devon's largest Permian Basin property.

     Production in this field was established in the 1930's, with most
of the current producing wells 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.  The project included drilling approximately 
185 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 30 producing wells 
to injection wells.

      At  year-end 1997, production averaged approximately 3,000 Boe per
day. Devon anticipates that continued water injection and completion of 
the waterflood facilities 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 9,000 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  NEBU, in Rio Arriba
and San Juan Counties, and the 22,400 acre 32-9 Unit in San Juan County.
The San Juan Basin, a densely drilled area  covering 3,700 square miles
in central and northwestern New Mexico, 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 97%, or 144.5 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
which  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 1998.   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 portion of the line looping  and 
compression projects that have been completed through February 24, 1998,
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 
209 MMcf of gas per day in January 1998.  Devon anticipates  that the
installation of additional compression and facilities could increase
production from NEBU another 10 MMcf to 20  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 enhance 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 will range  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, which 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  Field. The House Creek Field is located in 
Campbell County, Wyoming within the prolific Powder River Basin. 
Devon acquired its original interest in the field at year-end 1996.
In 1997, the Company purchased additional interests.  The field, 
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 Field 
is divided into two production units.  The southern two-thirds of the 
field, designated as the House Creek Sussex Unit, is operated by Devon with
a 45.4% working interest. A  12  well infill drilling program was initiated
late in 1997.  Based on the success of that program, an additional 
60 to 80 wells could be drilled in 1998, effectively reducing well 
spacing from  160 to 80 acres per well. The northern third of the field,
designated as the House Creek North Sussex Unit, is operated by a third
party.   Devon has a 26.5% working interest in the North Unit.  
Additional infill drilling is also underway in the North Unit.
Both portions of the field are currently under waterflood.

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 February 24, 1998,
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

      No  matters  were  submitted to a  vote  of  the Company's 
security  holders  during the fourth quarter of the year ended
December 31, 1997.


                        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.

     The following table sets forth the high and low sales prices for Devon
common stock as reported by the AMEX for the  periods indicated.
<TABLE>
<CAPTION>
                                                            Consolidated
                                                                 Average   
                                                                   Daily
                                     High            Low          Volume

 1996:
 <S>                                <C>             <C>           <C>
 Quarter Ended March 31, 1996       25-3/4          19-7/8        44,846
 Quarter Ended June 39, 1996        26-1/8          22            39,268
 Quarter Ended September 30, 1996   27-1/2          22-3/4        73,678
 Quarter Ended December 31, 1996    36-7/8          25-1/4        93,606
 1997:                             
 Quarter Ended March 31, 1997       38-7/8          29-1/2        73,079
 Quarter Ended June 30, 1997        38-1/2          27-3/8        87,800
 Quarter Ended September 30, 1997   45-1/4          36-1/8         6,174
 Quarter Ended December 31, 1997    49-1/8          35            69,694
 1998:
 Quarter Ended March 31, 1998       38-3/8          33            93,914
 (through February 24, 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.
Total dividends for the years ended December 31, 1994  and 1995 were 
$0.12 per share. Effective December 31, 1996, Devon increased its quarterly
dividend payment to $0.05  per share,  making the total dividends paid in
1996 $0.14 per share.  Total dividends for 1997 were $0.20 per share.  
Devon anticipates continuing to pay regular quarterly dividends in the
foreseeable future. 

      On February 24, 1998, there were 859 Devon Common Stock
shareholders of record.


   ITEM 6.   SELECTED FINANCIAL DATA

        The following selected financial information (not covered
   by  the  independent  auditors'  report)  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."
<TABLE>
<CAPTION>
                                                                                 
                                                Year Ended December 31,
                                     1997      1996       1995       1994     1993
                                     (Thousands, Except Per Share Data and Ratios)
   OPERATING RESULTS

      <S>                         <C>          <C>        <C>       <C>      <C>
      Oil sales                   $ 133,445    80,142     55,290    38,086   38,395
      Gas sales                     150,549    68,049     50,732    56,372   54,876
      NGL sales                      21,754    14,367      6,404     4,908    4,544
      Other revenue                   7,392     1,459        877     1,407      942

      Total revenues              $ 313,140   164,017    113,303   100,773   98,757

      Lease operating expenses    $  65,655    31,568     27,289    24,521   26,401
      Production taxes            $  17,924    10,658      6,832     6,899    6,924
      Depreciation, depletion and
        amortization              $  85,307    43,361     38,090    34,132   28,409
      General and administrative
        expenses                  $  12,922     9,101      8,419     8,425    7,640
      Interest expense            $     274     5,277      7,051     5,439    3,422
      Distributions on preferred
        securities of subsidiary
        trust                     $   9,717     4,753         --        --       --

<F1>
      Net earnings                $  75,292    34,801     14,502    13,745   20,4861

      Net earnings per share:
<F1>
              Basic               $    2.34      1.57       0.66      0.64     0.98 1
<F1>
              Diluted             $    2.17      1.52       0.65      0.63     0.98 1

      Cash dividends per common
        share                     $    0.20      0.14       0.12      0.12     0.09

      Weighted average common
        shares outstanding - basic   32,216    22,160     22,074    21,552   20,822

      Ratio of earnings to fixed
<F2>
        charges 2                     12.52      6.76       4.54      4.80     8.24

<CAPTION>
                                                                             
                                                          December 31,
                                     1997      1996        1995      1994     1993
                                                          (Thousands)
   BALANCE SHEET DATA

   Total assets                   $ 846,403   746,251    421,564   351,448  285,553
   Long-term debt                 $       -     8,000    143,000    98,000   80,000
   Convertible preferred securities
     of subsidiary trust          $ 149,500   149,500         --        --       --
   Stockholders' equity           $ 543,576   472,404    219,041   206,406  172,900

<CAPTION>
                                               Year Ended December 31,
                                     1997      1996        1995      1994     1993
                                           (Thousands, Except Per Unit Data)
   CASH FLOW DATA
      Net cash provided by
        operating activities      $ 168,722    86,802     61,276    46,384   63,957
<F4>
<F3>
      EBITDA 3,4                    216,639   112,689     70,763    60,928   57,792
<F4>
<F5>
      Cash margin 4,5               181,445    95,951     59,217    55,074   52,893

   PRODUCTION, PRICE AND OTHER DATA
      Production:
              Oil (MBbls)             7,005     3,816     3,300      2,467    2,337
              Gas (MMcf)             69,327    35,714    36,886     39,335   35,598
              NGLs (MBbls)            1,626       952       600        501      411
<F6>
              MBoe  6                20,185    10,720    10,047      9,524    8,681

      Average prices:
              Oil (Per Bbl)          $19.05     21.00     16.75      15.44    16.43
              Gas (Per Mcf)          $ 2.17      1.91      1.38       1.43     1.54
              NGLs (Per Bbl)         $13.38     15.09     10.68       9.79    11.06
<F6>
              Per Boe  6             $15.15     15.16     11.19      10.43    11.27

      Costs per Boe:
              Operating costs        $ 4.14      3.94      3.40       3.30     3.84
              Depreciation, depletion
                and amortization of
                oil and gas
                properties           $ 4.08      3.88      3.65      3.45      3.16
              General and administra-
                tive expenses        $ 0.64      0.85      0.84      0.89      0.88
                                              
<F1>
    1  Net earnings for 1993 include the cumulative effect of a required change
      in  the method  of accounting  for income  taxes in 1993  which provided
      earnings of $1.3 million, or $0.06 per share.

<F2>
    2  For purposes of calculating the ratio of earnings to  fixed charges, (i)
      earnings consist of earnings before  income taxes and cumulative  effect
      of accounting change, plus fixed charges; and (ii) fixed charges consist
      of interest expense, distributions on preferred securities of subsidiary
      trust, amortization of costs relating  to indebtedness and the preferred
      securities  of  subsidiary  trust,   and  one-third  of  rental  expense
      estimated to be attributable to interest.

<F3>
    3  EBITDA represents  earnings before interest (including  distributions on
      preferred   securities  of   subsidiary  trust),   taxes,  depreciation,
      depletion and amortization.

<F4>
    4  EBITDA and cash margin (defined below) are indicators which are commonly
      used in  the oil and gas industry.   They 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 in  analyzing Devon's  results of  operations and
      liquidity.

      For the years ended December  31, 1997, 1996, 1995, 1994, and  1993, net
      cash used in  investing activities were  $131.3 million, $94.8  million,
      $110.6  million, $73.4  million  and $74.2  million, respectively.   For
      these same  periods, net  cash provided (used)  by financing  activities
      were  ($4.5) million,  $8.5 million,  $49.8 million,  $15.8  million and
      $24.2 million, respectively.

<F5>
    5  "Cash margin" equals total  revenues less cash expenses.   Cash expenses
      are  all expenses  other  than the  non-cash  expenses of  depreciation,
      depletion and amortization 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.

<F6>
    6  Gas is 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 1995  through 1997. Reference
   is  made to  "Item 6.  Selected Financial  Data" and  "Item 8.
   Financial Statements  and Supplementary Data."

   Overview

        Devon concluded 1997 financially stronger and larger than
   at any previous time  in the company s history. Over  the last
   three years Devon's oil and gas reserves have grown 74% to 184
   million barrels  of oil  equivalent ("MMBoe").  The  company s
   unused long-term credit lines have increased 64% over the same
   period,  to $208 million.  Total assets have increased 141% to
   $846  million. During the  same three years  Devon reduced its
   long-term  debt from  $98  million to  zero and  significantly
   increased stockholders  equity.

        Devon s operating performance  has also improved  by most
   measures  over  the last  three years.  The  1997 oil  and gas
   production of 20.2 MMBoe was 112% over that of 1994.  The 1997
   production increase, coupled with  a 45% increase in  oil, gas
   and  NGL prices over 1994 levels, led to revenues and earnings
   gains.  Net earnings for 1997 climbed 448% over those of 1994,
   to $75.3  million. Net  cash provided by  operating activities
   rose from $46.4  million in  1994 to $168.7  million in  1997.
<F1>
   The cash  margin1 (total  revenues less  cash expenses)  during
   these  same three  years has increased  from $55.1  million in
   1994 to $181.4 million in 1997.

        This  growth in  operations was  driven primarily  by the
   following events: 

             Devon acquired Alta Energy Corporation through a $72
             million cash  and common  stock merger in  May 1994.
             The merger  added substantial oil  and gas reserves,
             production  and  revenues to  Devon's  Permian Basin
             position.

             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 added approximately $8 million, $10
                              
<F1>
1   "Cash margin" equals Devon's total revenues less cash expenses.   Cash
expenses are all expenses other than  the non-cash  expenses  of depreci-
ation,  depletion  and amortization  and  deferred income  tax expense.  Cash
margin is  an indicator  which is commonly  used in  the oil and  gas
industry.   This 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 effects on  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.   Cash  margin should  be used  as a
supplement  to, and  not  as  a substitute  for,  net  earnings and  net
cash provided  by  operating activities  determined  in  accordance with 
generally  accepted  accounting  principles in  analyzing Devon's results of
operations and liquidity.


             million and $12  million to Devon's  annual revenues
             in 1997, 1996 and 1995, respectively.  See Note 3 to
             the   consolidated  financial   statements  included
             elsewhere in  this report for  a detailed discussion
             of the San Juan Basin Transaction.

             On December  31, 1996,  Devon acquired all  of Kerr-
             McGee Corporation's  North American onshore  oil and
             gas   exploration   and   production  business   and
             properties (the "KMG-NAOS  Properties") in  exchange
             for 9,954,000  shares of  Devon common stock.   This
             transaction  added approximately  62 million  Boe to
             Devon's year-end 1996  proved reserves (an  increase
             of  over 50%),  as well  as 370,000  net undeveloped
             acres of leasehold.

             Devon has  been  successful during  the  last  three
             years in its drilling  efforts.  During such period,
             Devon has spent approximately $246 million to  drill
             688 wells, of which 667 were completed as producers.

             Prices received from oil,  gas and NGL revenues have
             risen (though  with volatility) 45%, from $10.43 per
             Boe in 1994 to $15.15 per Boe in 1997.
    
        The  following  actions  during  the  last  three   years
   improved  Devon s  liquidity  and  financial  resources  while
   reducing its bank debt:

             Devon's production  and revenue gains have given the
             company a substantially larger cash flow  and, thus,
             capital budget.

             Devon's  acquisition and drilling efforts during the
             last three  years have  added 120.4 MMBoe  of proved
             reserves to its asset base.  Combined with 1.8 MMBoe
             of   upward  revisions  to  its  reserve  estimates,
             Devon's  total  reserve  additions  of  122.2  MMBoe
             during  the  past  three  years  were  298%  of  its
             production of 41.0 MMBoe.

             In   July,  1996,  Devon,   through  a  newly-formed
             affiliate trust, issued $149.5 million of 6.5% Trust
             Convertible    Preferred   Securities    (the   "TCP
             Securities").     Combined   with  cash   flow  from
             operations, this transaction has  eliminated Devon's
             long-term debt.

             Devon's  oil and  gas reserve  additions, production
             gains, revenue  increases and equity  additions over
             the past three years  have allowed Devon to increase
             its  unused lines of credit.  Since the end of 1994,
             Devon's  available  long-term   credit  lines   have
             increased  by $81 million to a total of $208 million
             at year-end 1997.

        The growth exhibited by Devon  over the last three  years
   extends  a nine-year  expansion period for the company.  This
   period  began with  Devon becoming  a public company  in 1988.
   Through  its acquisitions  and  its  drilling and  development
   efforts,  Devon  has  significantly  increased   oil  and  gas
   reserves and production over this period.

        While  Devon has  consistently increased  production over
   this nine-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 the company produces.  However,
   Devon s future  growth, if any,  will depend on  the company s
   ability to continue to add reserves in excess of production. 

        Given the  dependence of oil  and gas  prices on  factors
   outside  of  Devon's  control, the  company s  management  has
   focused its  efforts on  increasing oil  and gas reserves  and
   production and  on controlling expenses.   Over its  nine year
   history  as  a  public  company,   Devon  has  been  able   to
   significantly  reduce its production  and operating  costs per
   unit of production. However, over the last three years Devon s
   per-unit operating costs have increased by 25%. An increase in
   the  company s  oil  production  as  a  portion of  its  total
   production and an increase in secondary recovery projects have
   contributed  to  this  expense  increase.  (Secondary recovery
   projects are generally more expensive than primary production.
   In addition,  producing oil  is generally more  expensive than
   producing  gas.   However,  oil also  generally produces  more
   revenue per Boe  than gas.)  Higher oil,  gas and NGL revenues
   in 1997  also resulted in higher production taxes, a component
   of production and operating expenses.  Devon s future earnings
   and  cash  flows are  dependent  on the  company s  ability to
   continue to  contain production and operating  costs at levels
   that  allow  for  profitable production  of  its  oil and  gas
   reserves. 

   Results of Operations

        Devon's total revenues have  risen from $113.3 million in
   1995 to $164.0 million in 1996 and $313.1 million in 1997.  In
   each of these years, oil, gas and NGL sales accounted for over
   97% of total revenues.

        Changes  in  oil,  gas  and NGL  production,  prices  and
   revenues  from  1995 to  1997 are  shown  in the  table below.
   (Note:  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,
                                                     1997                 1996
                                            1997    vs 1996     1996    vs 1995   1995
                                                   (Absolute Amounts in Thousands)

   Production
     <S>                                    <C>       <C>       <C>      <C>      <C>
     Oil (MBbls)                            7,005     +84%      3,816    +16%     3,300
     Gas (MMcf)                            69,327     +94%     35,714     -3%    36,886
     NGLs (MBbls)                           1,626     +71%        952    +59%       600
     Oil, Gas and NGLs (MBoe)              20,185     +88%     10,720     +7%    10,047

   Revenues
     Per Unit of Production:
       Oil (per Bbl)                      $ 19.05      -9%      21.00    +25%     16.75
       Gas (per Mcf)                      $  2.17     +14%       1.91    +38%      1.38
       NGLs (per Bbl)                     $ 13.38     -11%      15.09    +41%     10.68
       Oil, Gas and NGLs (per Boe)        $ 15.15       -       15.16    +35%     11.19

     Absolute:
       Oil                               $133,445     +67%     80,142    +45%    55,290
       Gas                               $150,549    +121%     68,049    +34%    50,732
       NGLs                              $ 21,754     +51%     14,367   +124%     6,404

       Oil, Gas and NGLs                 $305,748     +88%    162,558    +45%   112,426

<CAPTION>
                                                                Domestic
                                                       Year Ended  December 31,
                                                      1997                1996
                                           1997     vs 1996    1996     vs 1995   1995
                                                    (Absolute Amounts in Thousands)

   Production
     Oil (MBbls)                           6,055      +59%      3,816    +16%     3,300
     Gas (MMcf)                           61,015      +71%     35,714     -3%    36,886
     NGLs (MBbls)                          1,468      +54%        952    +59%       600
     Oil, Gas and NGLs (MBoe)             17,692      +65%     10,720     +7%    10,047

   Revenues
     Per Unit of Production:
       Oil (per Bbl)                     $ 19.08       -9%      21.00    +25%     16.75
       Gas (per Mcf)                     $  2.28      +19%       1.91    +38%      1.38
       NGLs (per Bbl)                    $ 13.18      -13%      15.09    +41%     10.68
       Oil, Gas and NGLs (per Boe)       $ 15.48       +2%      15.16    +35%     11.19

     Absolute:
       Oil                              $115,504      +44%     80,142    +45%    55,290
       Gas                              $139,018     +104%     68,049    +34%    50,732
       NGLs                             $ 19,338      +35%     14,367   +124%     6,404

       Oil, Gas and NGLs                $273,860      +68%    162,558    +45%   112,426

<CAPTION>
                                                               Canada
                                                      Year Ended  December 31,
                                                      1997                1996
                                           1997      vs 1996    1996     vs 1995   1995
                                                 (Absolute Amounts in Thousands)

   Production
     Oil (MBbls)                            950       N/A          -      N/A         -
     Gas (MMcf)                           8,312       N/A          -      N/A         -
     NGLs (MBbls)                           158       N/A          -      N/A         -
     Oil, Gas and NGLs (MBoe)             2,493       N/A          -      N/A         -

   Revenues
     Per Unit of Production:
       Oil (per Bbl)                    $ 18.89       N/A          -      N/A         -
       Gas (per Mcf)                    $  1.39       N/A          -      N/A         -
       NGLs (per Bbl)                   $ 15.28       N/A          -      N/A         -
       Oil, Gas and NGLs (per Boe)      $ 12.79       N/A          -      N/A         -

     Absolute:
       Oil                              $17,941       N/A          -      N/A         -
       Gas                              $11,531       N/A          -      N/A         -
       NGLs                             $ 2,416       N/A          -      N/A         -
       Oil, Gas and NGLs                $31,888       N/A          -      N/A         -
</TABLE>

      Oil Revenues  1997 vs. 1996  Oil revenues increased by $53.3
   million  in 1997.   Production  gains of  3.2  million barrels
   added  $67.0 million of oil  revenues in 1997.   This increase
   was  partially offset  by  a $13.7  million  reduction in  oil
   revenues  caused by a $1.95 per barrel decrease in the average
   oil price in 1997.

     The KMG-NAOS Properties acquired at the end of 1996 were the
   primary contributors to the  increased oil production in 1997.
   These properties  1997 production totaled 3.1 million barrels.
   Approximately 2.1  million barrels of such  production were in
   the  U.S., while 1 million  barrels were produced  in Canada. 
   Devon s other domestic properties produced 3.9 million barrels
   in 1997.   This was an increase of 0.1 million barrels, or 3%,
   over the 1996 production of 3.8 million barrels.

     1996  vs. 1995  Oil  revenues increased by  $24.9 million in
   1996.  An increase in the average price of $4.25 per barrel in
   1996  added $16.2  million to  revenues.  Production  gains of
   516,000  barrels added  the remaining  $8.7 million  of 1996's
   increased oil revenues.

     The Grayburg-Jackson  Field acquired in  1994 accounted  for
   the  majority  of 1996's  increased  production.   This  field
   produced  1.1 million barrels in 1996, a 37% increase over the
   807,000 barrels the field produced  in 1995.  Production  from
   Devon's other oil  properties increased 9%  in 1996, from  2.5
   million barrels in 1995 to 2.7 million barrels in 1996.

     Gas Revenues  1997 vs. 1996  Gas revenues increased by $82.5
   million in 1997.  An increase  in production of 33.6 Bcf added
   $64.0  million to 1997 s gas  revenues.  An  increase of $0.26
   per Mcf in the average price added $18.5 million to 1997 s gas
   revenues.

     The KMG-NAOS Properties were responsible for the majority of
   the  increased  gas  production  in 1997.    These  properties
   produced 29.8 Bcf  in 1997.   Approximately 21.5  Bcf of  such
   production  was in  the U.S.,  while 8.3  Bcf was  produced in
   Canada.  Devon s coal seam gas properties produced 17.6 Bcf in
   1997 compared to  17.4 Bcf  in 1996.   Devon s other  domestic
   properties produced 21.9 Bcf  in 1997 compared to 18.3  Bcf in
   1996.

     Devon s 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.

     Devon s domestic conventional  gas properties averaged $2.34
   per Mcf in 1997 compared to $2.08 per Mcf in 1996.

     1996  vs. 1995  Gas  revenues increased by  $17.3 million in
   1996.  An increase in  the average gas price of $0.53  per Mcf
   in  1996 added  $18.9 million  to 1996's  gas revenues.   This
   increase was partially  offset by a $1.6  million reduction in
   gas revenues from a drop in gas production of 1.2 Bcf.  

     Coal seam gas production  declined by 16%, from 20.8  Bcf in
   1995 to  17.4 Bcf in 1996.  However, the average realized coal
   seam gas price rose by 30% from $1.32 per Mcf in 1995 to $1.72
   per  Mcf in  1996.   Coal  seam  gas revenues  included  $10.3
   million  in 1996 and $12.8 million in 1995 attributable to the
   San Juan  Basin Transaction.   This transaction  increased the
   average coal seam gas price by $0.59 per Mcf in 1996 and $0.61
   per Mcf in 1995.

     Total conventional gas production and revenues for 1996 were
   18.3 Bcf and $37.9 million,  respectively, versus 16.1 Bcf and
   $23.2 million in 1995.   Prices for conventional  gas averaged
   $2.08 per Mcf in 1996 compared to 1995's average of $1.44.

     NGL Revenues  1997 vs. 1996   NGL revenues increased by $7.4
   million in 1997.  An increase in production of 674,000 barrels
   added  $10.2 million to  1997 s revenues.   This  increase was
   partially offset  by a $2.8 million reduction  in NGL revenues
   caused by a $1.71 per barrel decrease in 1997 s average price.

     The majority of  the increased  NGL production  in 1997  was
   attributable  to the  KMG-NAOS Properties.    These properties
   produced  339,000 barrels in  the U.S. and  158,000 barrels in
   Canada in 1997.

     1996 vs. 1995   NGL  revenues increased by  $8.0 million  in
   1996.  An increase in average prices of $4.41 per barrel added
   $4.2 million to  the 1996  NGL revenues.   The remaining  $3.8
   million of increased  revenues was  attributable to  increased
   production of 352,000 barrels in 1996.

     Additional  interests acquired in certain Wyoming properties
   in  December 1995  and the  first half  of 1996  accounted for
   214,000 barrels  of the increased  production in 1996.   These
   Wyoming properties  produced 226,000 barrels in  1996 compared
   to  12,000 barrels in 1995.   Additional drilling  in the Sand
   Dunes area of the Permian Basin increased production from that
   area from 69,000 barrels in 1995 to 95,000 barrels in 1996.

     Other  Revenues.  1997 vs. 1996  Other revenues increased by
   $5.9 million in  1997.  Revenues  from processing third  party
   natural gas  related to the KMG-NAOS  Properties accounted for
   $3.3  million of the increase.  An increase in interest income
   provided another $1.7 million of the  increase in 1997 s other
   revenues.

     1996 vs.  1995 Other  revenue increased  by $0.6 million  in
   1996.  Increases in gains recognized from the disposal of non-
   oil  and gas fixed assets and from settlements of gas contract
   claims accounted for most of this increase.

     Expenses   The details  of the  changes in  pre-tax expenses
   between 1995 and 1997 are shown in the table below.
<TABLE>
<CAPTION>
                                                                                                           
                                                       Year Ended December 31,
                                                         1997                 1996
                                             1997      vs 1996     1996     vs 1995   1995
                                                    (Absolute Amounts in Thousands)

         Absolute:
     Production and operating expenses:
       <S>                                 <C>          <C>       <C>        <C>    <C>
       Lease operating expenses            $ 65,655     +108%     31,568     +16%   27,289
       Production taxes                      17,924      +68%     10,658     +56%    6,832
     Depreciation, depletion and amortiza-
       tion of oil and gas properties        82,413      +98%     41,538     +13%   36,640

         Subtotal                           165,992      +98%     83,764     +18%   70,761

     Depreciation and amortization of
       non-oil and gas properties             2,894      +59%      1,823     +26%    1,450
     General and administrative expenses     12,922      +42%      9,101      +8%    8,419
     Interest expense                           274      -95%      5,277     -25%    7,051
     Distributions on preferred securities
       of subsidiary trust                    9,717     +104%      4,753      N/A        -

         Total                             $191,799      +83%    104,718     +19%   87,681

   Per Boe Produced:
     Production and operating expenses:
       Lease operating expenses              $ 3.25      +10%       2.95      +8%     2.72
       Production taxes                        0.89      -10%       0.99     +46%     0.68
     Depreciation, depletion and amortization
       of oil and gas properties               4.08       +5%       3.88      +6%     3.65

         Subtotal                              8.22       +5%       7.82     +11%     7.05

     Depreciation and amortization of non-oil
<F1>
       and gas properties (1)                  0.15      -12%       0.17     +21%     0.14
<F1>
     General and administrative expenses (1)   0.64      -25%       0.85      +1%     0.84
<F1>
     Interest expense (1)                      0.01      -98%       0.49     -30%     0.70
     Distributions on preferred securities of 
<F1>
      subsidiary trust (1)                     0.48       +9%       0.44     N/A         -

        Total                              $   9.50       -3%       9.77     +12%     8.73


<F1>
   (1)      Though  per  Boe  general and  administrative  expenses,  interest
            expense, non-oil  and gas property  depreciation and distributions
            on preferred  securities of  subsidiary trust may  be helpful  for
            profitability  trend  analysis, these  expenses  are not  directly
            attributable to production volumes. Rather they are an artifact of
            corporate structure, capitalization and financing, and non-oil and
            gas property fixed assets, respectively.

</TABLE>

      Production  and  Operating  Expenses   The  details  of  the changes  in
   production  and operating expenses  between 1995 and 1997  are shown in the
   table below.
<TABLE>
<CAPTION>
                                                                Total
                                                       Year Ended December 31,
                                                      1997                  1996
                                             1997    vs 1996      1996     vs 1995   1995
                                                   (Absolute Amounts in Thousands)

   Absolute:
     <S>                                   <C>         <C>       <C>        <C>     <C>
     Recurring lease operating expenses    $61,658     +118%     28,270     +19%    23,842
     Well workover expenses                  3,997      +21%      3,298      -4%     3,447
     Production taxes                       17,924      +68%     10,658     +56%     6,832

        Total production and operating
          expenses                         $83,579      +98%     42,226     +24%    34,121

   Per Boe:
     Recurring lease operating expenses     $ 3.05      +16%       2.64     +11%      2.37
     Well workover expenses                   0.20      -35%       0.31     -11%      0.35
     Production taxes                         0.89      -10%       0.99     +46%      0.68

        Total production and operating
          expenses                          $ 4.14       +5%       3.94     +16%      3.40

<CAPTION>
                                                                Domestic
                                                        Year Ended December 31,
                                                       1997                 1996
                                              1997    vs 1996     1996     vs 1995   1995
                                                   (Absolute Amounts in Thousands)

   Absolute:
     Recurring lease operating expenses     $54,969     +94%     28,270     +19%    23,842
     Well workover expenses                   3,143      -5%      3,298      -4%     3,447
     Production taxes                        17,646     +66%     10,658     +56%     6,832

        Total production and operating
          expenses                          $75,758     +79%     42,226     +24%    34,121

   Per Boe:
     Recurring lease operating expenses      $ 3.10     +17%       2.64     +11%      2.37
     Well workover expenses                    0.18     -42%       0.31     -11%      0.35
     Production taxes                          1.00      +1%       0.99     +46%      0.68

        Total production and operating
          expenses                           $ 4.28      +9%      3.94      +16%      3.40

<CAPTION>
                                                                  Canada
                                                        Year Ended December 31,
                                                       1997                 1996
                                              1997    vs 1996     1996     vs 1995    1995
                                                    (Absolute Amounts in Thousands)

   Absolute:
     Recurring lease operating expenses     $ 6,689     N/A          -       N/A        -
     Well workover expenses                     854     N/A          -       N/A        -
     Production taxes                           278     N/A          -       N/A        -

        Total production and operating
          expenses                          $ 7,821     N/A          -       N/A        -

   Per Boe:
     Recurring lease operating expenses      $ 2.68     N/A          -       N/A        -
     Well workover expenses                    0.35     N/A          -       N/A        -
     Production taxes                          0.11     N/A          -       N/A        -

        Total production and operating
          expenses                           $ 3.14     N/A          -       N/A        -
</TABLE>

      1997 vs. 1996   Recurring  lease operating expenses  increased by  $33.4
   million,  or 118%,  in 1997.   The KMG-NAOS Properties  accounted for $26.0
   million of the increased expenses.  Most of  the remaining $7.4 million  of
   1997 s increase was due to wells which were drilled in 1997 and 1996.

      Recurring  expenses per Boe were  up by $0.41 per Boe,  or 16%, in 1997.
   This increase was caused  by the reduction in the coal seam gas properties 
   share of total production.   The recurring operating costs per Boe for  the
   coal seam  gas properties  are extremely  low ($0.43  per Boe  in 1997  and
   $0.32 per  Boe in  1996).   However,  as production  from these  properties
   remained  relatively flat  and  production from  Devon s  other  properties
   increased in  1997, the  coal seam  gas properties   percentage of  overall
   production dropped  from 27% in 1996  to only 15% in  1997.  The result  is
   that a larger  percentage of Devon s production in 1997 was attributable to
   its  conventional properties, which  have a  higher operating  cost per Boe
   than the low-cost coal seam gas properties.   The recurring operating costs
   per Boe for Devon s conventional properties were $3.50 per Boe in 1997  and
   1996.   Thus, the  coal seam properties' costs  rose only $0.11 per  Boe in
   1997  and  the  conventional  properties'  costs  remained  flat  in  1997.
   However, since the conventional properties represented a larger  percentage
   of Devon's total production in 1997 compared to  1996 (85% in 1997 compared
   to 73% in 1996),  the result was a  $0.41 per  Boe increase in the  overall
   rate.

      Most taxing authorities collect  production taxes on a  fixed percentage
   of revenue basis.  Therefore,  as Devon s revenues have  increased, so have
   production  taxes.  Production  taxes increased  68% from  $10.7 million in
   1996 to $17.9 million  in 1997.  This increase  was due to the 88% increase
   in combined oil, gas and NGL revenues in 1997.

      1996  vs. 1995   Recurring  lease operating  expenses increased  by $4.4
   million, or 19%, in  1996.  Approximately $2.7 million of the increase  was
   related to the additional interests acquired  in the Worland Properties  in
   December  1995 and  the first  half  of 1996.   Recurring  lease  operating
   expenses  for the Worland Properties increased from $0.1 million in 1995 to
   $2.8  million  in  1996  after  Devon   increased  its  ownership  in  such
   properties.   Most of  the remaining  $1.7 million increase was  due to the
   higher number  of producing  wells in  the Grayburg-Jackson  Field in  1996
   compared to 1995.

      Recurring expenses per Boe were up by $0.27, or 11%, in 1996 compared to
   1995.  As explained above  in the 1997 vs. 1996 discussion, the increase in
   the percentage  of production  attributable to  conventional properties  is
   also the cause  of the increase in per Boe costs in 1996  compared to 1995.
   The recurring  costs for the  coal seam gas  properties averaged $0.32  per
   Boe in 1996 and $0.24 per  Boe in 1995.  The  recurring expenses of Devon's
   conventional oil and  gas properties were $3.50 per  Boe in 1996 and  1995.
   Thus,  the coal seam properties' costs rose only $0.08  per Boe in 1996 and
   the  conventional  properties'  costs   per  Boe  remained  flat  in  1996.
   However, since the conventional properties represented a larger  percentage
   of Devon's total production in 1996 compared to  1995 (73% in 1996 compared
   to 65%  in 1995),  the result was a  $0.27 per Boe increase  in the overall
   rate.

      Production  taxes increased  56%  from $6.8  million  in 1995  to  $10.7
   million in 1996.  This  increase was primarily due to  the 45% increase  in
   combined oil, gas and NGL revenues.

      Production taxes  per Boe increased by  $0.31 per Boe, or  46%, in 1996.
   This was  primarily caused  by the increase  in the average  price per  Boe
   received in 1996.

      Depreciation,  Depletion  and  Amortization    Devon's  largest non-cash
   expense is depreciation,  depletion and amortization ("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.

      1997  vs.  1996   Oil  and  gas  property related  DD&A  increased $40.9
   million, or  98%, in 1997.   Approximately $36.7  million of this  increase
   was caused by the 88% increase in  combined oil, gas and NGL  production in
   1997.  The remaining $4.2  million of increase was caused by a 5%  increase
   in the DD&A rate from $3.88 per Boe in 1996 to $4.08 per Boe in 1997.

      1996  vs. 1995   Oil  and gas  property related  DD&A increased  by $4.9
   million, or 13%, in 1996.  Approximately $2.5  million of this increase was
   caused  by a 7% increase in total oil, gas and NGL production in 1996.  The
   remaining $2.4  million increase was caused  by a 6%  increase in the  DD&A
   rate from $3.65 per Boe in 1995 to $3.88 per Boe in 1996.

      General  and Administrative  Expenses  ("G&A")    1997  vs.  1996    G&A
   increased by $3.8 million, or 42%, in 1997.   Employee salaries and related
   overhead costs, including insurance  and pension expense, increased by $4.9
   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 addition of the KMG-NAOS  Properties.  The expansion in
   personnel  also caused  office-related  costs such  as rent,  dues, travel,
   supplies, telephone, etc., to increase by $1.8 million in 1997.

      The higher salary, overhead and office costs were 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.
   Due to  the  addition  of  the KMG-NAOS  Properties,  many of  which  Devon
   operates,  Devon s overhead  reimbursements increased  by $3.7  million  in
   1997.

      1996 vs. 1995  G&A increased by $0.7 million, or 8%, in 1996.   Employee
   salaries  and related  benefits were  $1.1 million  higher in 1996.   Legal
   expenses and  abandoned acquisition expenses  were each $0.2 million higher
   in  1996.    These  increases  were  partially  offset  by  a  $0.1 million
   reduction  in  franchise  tax  expense  due   to  Devon's  1995  change  of
   incorporation from Delaware  to Oklahoma.  Also,  Devon saw a $0.7  million
   increase  in  G&A reimbursements  received from  joint  interest owners  in
   Devon-operated properties.

      Interest  Expense    1997 vs.  1996    Interest  expense decreased  $5.0
   million, or  95%, in  1997.   This decrease  was caused  by a  drop in  the
   average  debt  balance outstanding  from  $77.0  million  in  1996 to  $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
   Devon s  long-term bank  debt  early in  1997.   (The  TCP  Securities  are
   discussed further below.)

      1996 vs.  1995  Interest expense  decreased by $1.8 million,  or 25%, in
   1996.  Approximately $1.5 million of the lower interest expense was due  to
   a lower  average debt balance  in 1996.   The average  debt balance dropped
   from $97.1  million in 1995  to $77.0 million  in 1996.   This decrease  in
   average debt  outstanding was primarily  the result of the  issuance of the
   TCP Securities in July 1996.

      The  remaining  $0.3  million  of interest  expense  reduction  in  1996
   resulted  from lower  interest  rates.   The  interest rates  on  the  debt
   outstanding during 1996 averaged 6.3%, compared  to 1995's average rate  of
   6.5%.   The  overall interest  rate (including  the effect of  the interest
   rate  swap  discussed  below,  various  fees  paid  to  the banks  and  the
   amortization  of certain  loan costs)  averaged 6.9%  in  1996 and  7.3% in
   1995.

      Devon entered into an interest rate swap agreement in the second quarter
   of 1995  and terminated the agreement  on July 1, 1996  for a gain of  $0.8
   million.   This  gain is  being  recognized  ratably in  Devon's  operating
   results as a reduction  to interest expense during  the period from July 1,
   1996  to  June  16,  1998  (the  original  expiration  date  of  the   swap
   agreement).   Approximately  $0.2 million of  the gain was  included in the
   last half of  1996 as a  reduction to interest  expense.   During the  time
   when the  agreement was  still in effect,  it resulted in  $0.1 million  of
   reduced interest  expense in the  year 1995 and  had no  effect on interest
   expense for the first six months of 1996.

      Distributions on Preferred Securities of Subsidiary Trust  1997 vs. 1996
   As mentioned in the  above discussion of interest expense, 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 on the TCP  Securities accrue at the rate
   of 1.625% per  quarter.  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.

      1996 vs. 1995  The TCP Securities were issued in July, 1996.  The  1996
   distributions of $4.8 million represented slightly less than two  quarters'
   distributions due to the issuance date occurring in July.

      Income Taxes    1997 vs. 1996  Devon s  effective financial tax rate  in
   1997 was 38% compared to 41% in 1996.  Both rates were  above the statutory
   federal tax rate  of 35% due to state income taxes, and certain tax aspects
   of the San Juan Basin Transaction  and a 1994 merger.   Also, the 1997 rate
   was affected  by certain  tax aspects  of the  KMG-NAOS transaction  and by
   Canadian income taxes which accrue at rates higher  than the U.S. statutory
   rate  of  35%.   (The  effective  financial income  tax  rate  for  Devon's
   Canadian operations was 43% in 1997.)

      1996 vs.  1995   Devon s effective  financial tax rate  in 1996  was 41%
   compared  to 1995 s  rate  of 43%.    Both  rates  were above  the  federal
   statutory rate of 35% due to the effect  of the state taxes, San Juan Basin
   Transaction and 1994 merger noted in the above paragraph.

   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 $130.5 million of cash was spent in
   1997 for capital expenditures,  of which $124.6 million was related to  the
   acquisition,  drilling or development  of oil and gas  properties.  Most of
   the drilling  and  development efforts  in  1997  centered in  the  Permian
   Basin, which included 174 of  the 295 oil and gas wells that Devon  drilled
   during the year.

      Other  Cash Uses   A $0.03  per common share  dividend was paid  in each
   quarter since  Devon paid its  initial common stock dividend  in the second
   quarter of 1993 through the  third quarter of 1996.  In the fourth  quarter
   of 1996,  the quarterly  dividend rate  was increased  to $0.05  per share.
   Quarterly dividends in 1997 were paid at the rate of $0.05 per share.

      Capital  Resources  and  Liquidity    Net  cash  provided  by  operating
   activities ("operating  cash flow") was the  primary source  of capital and
   short-term liquidity in 1997.   Operating cash flow in  1997 totaled $168.7
   million,  a 94% increase  compared to the  $86.8 million  of operating cash
   flow generated in 1996.

      In  addition  to  operating  cash   flow,  Devon's  credit  lines   have
   historically been an important source of  capital and liquidity.   However,
   1997's  increased  operating cash  flow  allowed  Devon  to  fund its  1997
   capital  expenditures and  other cash  uses without  borrowing against  its
   credit lines.   At  the end  of 1997, Devon  had $208 million  of long-term
   credit  lines, all of which was available for future  use.  Also, Devon has
   a  $12.5  million  Canadian  dollars   demand  facility  for  its  Canadian
   operations.  All of  this Canadian facility  was also available at the  end
   of  1997 for  future  use.   (See  Note  7 to  the  consolidated  financial
   statements included elsewhere in this report  for a detailed discussion  of
   Devon's credit lines.)

   1998 Estimates

        The   forward-looking   statements   provided   in   this
   discussion are based on management's examination of historical
   operating  trends, the  December 31,  1997 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  NGL production,  revenues and
   expenses are  subject to  all of the  risks and  uncertainties
   normally incident  to the exploration for  and development and
   production and sale of  oil and gas. These risks  include, but
   are  not limited to,  price volatility,  inflation 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 for
   Devon's   Canadian  operations,   obtained  in   the  KMG-NAOS
   transaction,  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 NGL  prices may
   vary considerably  due to differences between regional markets
   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,  the  company 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
   company s  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.
   The company s interest  in NEBU and the  32-9 Unit 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 1998 will be substantially similar to
   those  of  1997, unless  otherwise  noted.  Given the  general
   limitations   expressed    herein,   Devon's   forward-looking
   statements for 1998 are set forth below.

        Oil Production and Relative Prices  Devon expects its oil
   production in  1998 to total  between 6.3 million  barrels and
   7.3 million barrels.   Devon  expects its net  oil prices  per
   barrel will average  from between  $0.20 to  $0.45 above  West
   Texas Intermediate posted prices in 1998.

        Gas  Production and  Relative Prices   Devon  expects its
   total gas production in 1998 will be between 67.0 Bcf and 78.5
   Bcf.   It is expected  that coal  seam gas production  will be
   between 19.0 Bcf and 22.2 Bcf.  Canadian production in 1998 is
   estimated  to be between 6.8  Bcf and 8.0 Bcf.   Devon expects
   production from the  remainder of its gas  properties to total
   between 41.2 Bcf and 48.3 Bcf.

        Devon  expects its 1998  coal seam average  price will be
   between $0.25 and  $0.55 per  Mcf less than  Texas Gulf  Coast
   spot averages.  This  includes an expected $0.40 to  $0.45 per
   Mcf from the San Juan Basin Transaction.  Devon's Canadian gas
   production is expected to average from between $0.80 to  $1.05
   less  than Texas  Gulf Coast  spot averages.   (These Canadian
   differentials are  expressed in U.S. dollars,  using the year-
   end  1997 exchange rate of $0.70 U.S. dollar to $1.00 Canadian
   dollar.)   Devon's  remaining  gas production  is expected  to
   average  $0.05 to  $0.25  less  than  Texas  Gulf  Coast  spot
   averages during 1998.

        Devon  had made  firm  commitments to  sell approximately
   12,700  Mcf per day of its coal seam gas production throughout
   1998  at a fixed price  of approximately $1.45  per Mcf, which
   equates  to a  price of  approximately $2.04  per  MMBtu. (The
   $1.45 per Mcf price  includes the effect of adjusting  for Btu
   content and  is net of  costs for transportation  and removing
   carbon dioxide.   This  price excludes the  expected $0.40  to
   $0.45 per Mcf  benefit from the  San Juan Basin  Transaction.)
   The effect of these fixed  price commitments has been included
   in  the expected differential  for coal seam  gas discussed in
   the above paragraph.  Devon has also made other commitments to
   sell certain quantities of  its 1998 domestic conventional and
   Canadian  gas  production  at  fixed prices.    However,  such
   commitments to date are not expected to have a material effect
   on Devon's  1998 gas price  differentials due  to the  limited
   quantities of gas per day involved.

        NGL Production   Devon expects its production  of NGLs in
   1998  to total  between 1.3  million barrels  and 1.5  million
   barrels.

        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   the  company s  property   base,  changes   in
   production taxes,  general changes  in the prices  of services
   and  materials that are used in the operation of the company s
   properties  and the  amount  of repair  and workover  activity
   required on the company s properties. 

        Oil,  gas and  NGL prices  will have  a direct  effect on
   production  taxes to be incurred in 1998.  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 NGL prices,  increase the
   uncertainty  inherent  in  estimating  future  production  and
   operating  costs. Given  these uncertainties,  Devon estimates
   that  1998's  total production  and  operating  costs will  be
   between $78.0 million and $90.5 million.

        Depreciation, Depletion  and Amortization   The 1998 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 1998 compared to  the
   costs incurred for such efforts,  and the revisions to Devon's
   year-end  1997 reserve  estimates  which will  be made  during
   1998.  

        The DD&A rate as  of the beginning of  1998 was 4.08  per
   Boe.  Assuming a 1998 rate  of between $4.10 per Boe and $4.45
   per Boe, 1998  oil and  gas property related  DD&A expense  is
   expected to  be  $85 million  to $93  million.   Additionally,
   Devon  expects its  non-oil and  gas property related  DD&A to
   total between $3 million and $4 million in 1998.

        General and Administrative Expenses  Devon s general  and
   administrative expenses  include the  costs of  many different
   goods and services  used in support of the company s business.
   These goods  and services are  subject to general  price level
   increases or decreases. In addition, Devon s G&A expenses vary
   with the company s level of activity and the related  staffing
   needs as  well as  with  the amount  of professional  services
   required  during  any  given  period.  Should  the   company s
   anticipated needs  or the  prices of  the required  goods  and
   services differ significantly from the company s expectations,
   actual G&A  expenses could vary materially  from the estimate.
   Given  these  limitations, G&A  expenses  are  expected to  be
   between $13 million and $15 million in 1998.

        Interest  Expense   Devon s  management expects  to  fund
   substantially all of its  anticipated expenditures during 1998
   with working  capital  and  internally  generated  cash  flow.
   Should  Devon s  actual  capital  expenditures  or  internally
   generated  cash  flow  vary significantly  from  expectations,
   interest  expense could differ  materially from  the following
   estimate. Given this limitation,  interest expense is expected
   to be less than $1 million in 1998.

        Distributions on  TCP  Securities    TCP  Securities  are
   convertible into common shares  of Devon at the option  of the
   holder. Any conversions of the TCP Securities would reduce the
   amount of required distributions.  Assuming all $149.5 million
   of  TCP Securities are outstanding for  the entire year, Devon
   will make $9.7 million of distributions in 1998. 

        Income Taxes  Devon expects its financial income tax rate
   in 1998 to be between 34% and 38%.  Regardless of the level of
   pre-tax earnings reported  for financial purposes, Devon  will
   have  a minimum  of  approximately $2.0  million of  financial
   income tax expense  due to  various aspects of  the 1994  Alta
   merger,  the  San  Juan  Basin Transaction  and  the  KMG-NAOS
   acquisition.  Therefore, if the  actual amount of 1998 pre-tax
   earnings differs materially from what Devon currently expects,
   the  actual financial  income tax rate  for 1998  could differ
   from the  expected rate  of 34%  to 38%.   Also, based  on its
   current expectations of 1998 taxable income, Devon anticipates
   its current portion of  1998 income taxes will be  between $12
   million and  $17 million.  However,  unanticipated revenue and
   earnings 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
   NGL  prices as  well  as the  expected  costs of  the  capital
   additions. Should  the company s  price expectations  for  its
   future   production  change  significantly,  the  company  may
   accelerate  or  defer  some  projects  and, consequently,  may
   increase  or  decrease  total 1998  capital  expenditures.  In
   addition,  if the  actual cost  of  the budgeted  items varies
   significantly  from  the  amount anticipated,  actual  capital
   expenditures could vary materially from Devon s estimate. 

        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  1998 capital
   expenditures  for drilling  and  development efforts  to total
   between $140 million and $160 million, including $8 million to
   $12  million in  Canada.   (Canadian amounts are  expressed in
   U.S. dollars, using  the year-end 1997 exchange  rate of $0.70
   U.S. dollar to $1.00 Canadian dollar.)  Devon expects to spend
   $45 million  to $60 million  in 1998 for  drilling, facilities
   and waterflood costs related  to reserves classified as proved
   as of year-end  1997.  Devon also  plans to spend another  $60
   million to $70 million on new, higher risk/reward projects.

        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 32.3  million
   shares  of  common  stock  outstanding,   1998  dividends  are
   expected to approximate $6.5 million.

        Capital  Resources and  Liquidity   The  estimated future
   drilling and development activities  are expected to be funded
   through a combination of working capital and net cash provided
   by  operations. The  amount  of net  cash  to be  provided  by
   operating activities in 1998  is uncertain due to the  factors
   affecting revenues  and expenses cited above.   However, Devon
   expects that its capital resources will  be more than adequate
   to fund its anticipated capital expenditures.

        Based   on  the   expected   level   of  1998's   capital
   expenditures and  net cash provided by  operations, Devon does
   not expect to  rely on  its existing  credit lines  to fund  a
   material  portion of  its capital  expenditures.   However, if
   significant   acquisitions   or   other    unplanned   capital
   requirements arise  during the  year, Devon could  utilize its
   existing  credit lines  and/or seek  to establish  and utilize
   other sources  of financing.   The unused portion  of existing
   credit lines at the end of  1997 consisted of $208 million  of
   long-term  credit facilities,  and  a  $12.5 million  Canadian
   dollars demand  facility for Devon's Canadian  operations.  If
   so desired, Devon believes that its lenders would increase its
   credit  lines  to  at  least  $450  million to  $500  million.
   However,  the company does not desire nor anticipate a need to
   increase its credit lines above their current levels.

        Potential Reduction in 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 is compared to the ceiling on a quarterly
   and annual basis.  Any excess of the net book value above the 
   ceiling is written off as an expense.

       At December 31, 1997, the Company's net book value of oil and
   gas properties less deferred taxes was well below the calculated 
   ceiling.  This excess "cushion" was $146 million for the Company's
   U.S. properties and $18 million for its Canadian properties.  By
   March 11, 1998 oil prices had declined significantly from year-end
   1997 levels.  There had also been a moderate decline in natural gas
   prices.  Based on these decreases, Devon estimated that its ceiling
   value on March 11, 1998 was significantly lower than at year-end
   1997.  However, the estimated ceiling value was still greater than 
   the book value of the Company's oil and gas properties less 
   deferred taxes.  Oil or gas price declines after March 11, 1998 
   could cause the ceiling value to fall below the recorded net book
   value.  The result would be a reduction in the carrying value 
   of the Company's oil and gas properties.  Should this occur, the 
   Company also would recognize a corresponding expense.     

        Impact of  Recently Issued  Accounting Standards  Not Yet
   Adopted   In  June, 1997,  the Financial  Accounting Standards
   Board issued  Statement of Financial  Accounting Standards No.
   130,   Reporting  Comprehensive  Income.    SFAS  No.  130  is
   effective for fiscal years  beginning after December 15, 1997.
   SFAS No.  130 establishes 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.   The  only component  of  comprehensive
   income that is not  currently included in Devon s consolidated
   statements  of   operations   is  the   currency   translation
   adjustment  reported as  part  of stockholders   equity as  of
   December 31, 1997.  Devon will adopt SFAS No. 130 in 1998.

        Also in  June,  1997, Statement  of Financial  Accounting
   Standards  No.  131,    Disclosures  about   Segments  of   an
   Enterprise and Related Information,  was issued.  SFAS No. 131
   is effective  for periods  beginning after December  15, 1997.
   SFAS  No. 131  requires that  publicly-traded  entities report
   financial   and   descriptive  information   about  reportable
   operating segments.   Operating segments are  components of an
   enterprise  about  which  separate  financial  information  is
   available that  is evaluated regularly by  the chief operating
   decision maker in  deciding how to  allocate resources and  in
   assessing performance.  Devon will adopt SFAS No. 131 in 1998.
   However,  such adoption  is not  expected to  have a  material
   impact   on  Devon s  current  financial  disclosures  because
   Devon s oil and  gas operations  are expected to  be the  only
   reportable operating segment under SFAS No. 131 s definitions.

        In January,  1997, the Securities and Exchange Commission
   issued  Release  #33-7386.    This  release requires  enhanced
   description  of accounting  policies for  derivative financial
   instruments  and  derivative   commodity  instruments  in  the
   footnotes  to  the financial  statements.    The release  also
   requires  quantitative and qualitative disclosures outside the
   financial statements  about market  risks inherent  in  market
   risk  sensitive  instruments  including  derivative  financial
   instruments,  derivative  commodity   instruments  and   other
   financial instruments.   The requirements regarding accounting
   policy  descriptions  were  effective  for  any  fiscal period
   ending  after  June 15,  1997.    However, because  derivative
   financial  or   commodity  instruments  have   not  materially
   affected Devon's financial position,  cash flows or results of
   operations, this part  of the release  did not affect  Devon's
   1997   disclosures.      The  quantitative   and   qualitative
   disclosures  set  forth  in  the  release  will  be  initially
   required  in Devon's annual report  on Form 10-K  for the year
   ending December 31, 1998. 

        Impact of the  Year 2000 Issue   An issue exists for  all
   companies that  rely on computers as the year 2000 approaches.
   This is because historically  many computer programs used only
   two digits to represent the year in dates.  Therefore, without
   adequate  modifications,  many  programs  will  not  correctly
   identify  the year 2000.  Devon plans  to install a  Year 2000
   Release  of  its commercial software during  1998.  
   In-house modifications  that have  been previously
   made  to the commercial software will also be upgraded at that
   time to be  year 2000  compliant.  Devon  anticipates that  it
   will be able to  install the new commercial software  release,
   upgrade its modifications and test  the entire system with its
   existing   internal  programming  staff.    Therefore,  future
   incremental  expenses, if any, incurred to  deal with the year
   2000 issue  are expected  to be immaterial  to Devon's  future
   operating results.

<PAGE>
   ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    Index to Consolidated Financial Statements and Consolidated
                   Financial Statement Schedules
                                                                 
                                                                 
                                                                          Page

   Independent Auditors' Report                                            44

   Consolidated Financial Statements:
     Consolidated Balance Sheets
          December 31, 1997, 1996 and 1995                                 45 

     Consolidated Statements of Operations
          Years Ended December 31, 1997, 1996 and 1995                     46

     Consolidated Statements of Stockholders' Equity
          Years Ended December 31, 1997, 1996 and 1995                     47

     Consolidated Statements of Cash Flows
          Years Ended December 31, 1997, 1996 and 1995                     48

     Notes to Consolidated Financial Statements
          December 31, 1997, 1996 and 1995                                 49

   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 consolidated  financial statements
   of  Devon Energy Corporation and subsidiaries as listed in the
   accompanying index.   These consolidated financial  statements
   are  the  responsibility of  the  Company's  management.   Our
   responsibility is to express  an opinion on these consolidated
   financial statements based on our audits.

          We conducted our  audits in  accordance with  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 provide a
   reasonable basis for our opinion.

          In  our opinion, the  consolidated financial statements
   referred to  above present  fairly, in all  material respects,
   the  financial  position  of  Devon   Energy  Corporation  and
   subsidiaries as of December  31, 1997, 1996 and 1995,  and the
   results of their operations and their cash flows for the years
   then ended,  in conformity with  generally accepted accounting
   principles.





                                            KPMG Peat Marwick LLP

   Oklahoma City, Oklahoma
   January 26, 1998
<PAGE>
<TABLE>
                    DEVON ENERGY CORPORATION AND SUBSIDIARIES
                           Consolidated Balance Sheets

<CAPTION>
                                                                December 31,
                                                      1997          1996          1995

   Assets
   Current assets:
              <S>                              <C>                <C>           <C>
              Cash and cash equivalents        $   42,064,344     9,401,350     8,897,891
              Accounts receivable (Note 5)         47,507,805    29,580,306    14,400,295
              Inventories                           2,422,822     2,103,486       605,263
              Prepaid expenses                        799,923       688,752       222,135
              Deferred income taxes (Note 8)          434,000     1,600,000       749,000

                 Total current assets              93,228,894    43,373,894    24,874,584

   Property and equipment, at cost, based on
     the full cost method of accounting for
     oil and gas properties (Note 6)            1,103,320,502   974,805,756   631,437,904
              Less accumulated depreciation,
                depletion and amortization        365,517,722   281,959,410   239,619,167

                                                  737,802,780   692,846,346   391,818,737
   Other assets                                    15,371,368    10,030,560     4,870,796

                 Total assets                 $   846,403,042   746,250,800   421,564,117

   Liabilities and stockholders' equity
   Current liabilities:
              Accounts payable:
                 Trade                              9,628,890     4,861,428     3,868,458
                 Revenues and royalties due
                   to others                       11,531,296    10,569,960     7,322,418
              Income taxes payable                  4,901,940     4,705,447     1,364,070
              Accrued expenses                      4,750,699     3,503,420     3,003,943

                 Total current liabilities         30,812,825    23,640,255    15,558,889

   Revenues and royalties due to others             2,862,794     1,259,129       889,173
   Other liabilities (Notes 3 and 11)              18,177,130    10,325,999     8,623,057
   Long-term debt (Note 7)                                  -     8,000,000   143,000,000
   Deferred income taxes (Note 8)                 101,474,000    81,121,000    34,452,000

   Company-obligated mandatorily redeemable
     convertible preferred securities of 
     subsidiary trust holding solely 6.5%
     convertible junior subordinated debentures
     of Devon Energy Corporation (Note 9)         149,500,000   149,500,000             -

   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 32,318,895 in 1997,
                 32,141,295 in 1996, 22,111,896
                 in 1995                            3,231,890     3,214,130     2,211,190
              Additional paid-in capital          392,919,170   388,090,930   167,430,347
              Retained earnings                   149,946,232    81,099,357    49,399,461
              Cumulative currency translation
                adjustment                         (2,520,999)            -             - 

                 Total stockholders' equity       543,576,293   472,404,417   219,040,998

   Commitments and contingencies (Notes 11 and 12)
                 Total liabilities and
                   stockholders' equity        $  846,403,042   746,250,800   421,564,117

   See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
                    DEVON ENERGY CORPORATION AND SUBSIDIARIES
                      Consolidated Statements of Operations

<CAPTION>
                                                          Year Ended December 31,
                                                      1997          1996         1995

   Revenues
              <S>                                <C>             <C>           <C>
              Oil sales                          $133,445,231    80,142,073    55,289,819
              Gas sales                           150,548,871    68,049,478    50,732,158
              Natural gas liquids sales            21,754,033    14,366,771     6,403,663
              Other                                 7,391,733     1,458,562       877,185

                  Total revenues                  313,139,868   164,016,884   113,302,825

   Costs and expenses
              Lease operating expenses             65,655,074    31,568,428    27,288,755
              Production taxes                     17,923,815    10,657,814     6,832,507
              Depreciation, depletion and
                amortization (Note 6)              85,306,868    43,361,029    38,089,783
              General and administrative expenses  12,922,259     9,101,429     8,418,739
              Interest expense                        273,821     5,276,527     7,051,142
              Distributions on preferred securities
                of subsidiary trust (Note 9)        9,717,502     4,753,125             -

                  Total costs and expenses        191,799,339   104,718,352    87,680,926

   Earnings before income taxes                   121,340,529    59,298,532    25,621,899

   Income tax expense (Note 8)
              Current                              25,202,000     6,709,000     4,495,000
              Deferred                             20,847,000    17,789,000     6,625,000

                Total income tax expense           46,049,000    24,498,000    11,120,000

   Net earnings                                  $ 75,291,529    34,800,532    14,501,899

   Net earnings per average common
              share outstanding (Note 1):
                Basic                                  $2.34          1.57           0.66
                Diluted                                $2.17          1.52           0.65

   Weighted average common shares
      outstanding - basic (Note 1)                32,215,745    22,159,507     22,073,550






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


<CAPTION>
                                                          Year Ended December 31,
                                                       1997         1996         1995

   Common stock
             <S>                                     <C>          <C>          <C>
             Balance, beginning of year              3,214,130    2,211,190    2,205,100
             Par value of common shares issued          17,760    1,002,940        6,090

             Balance, end of year                    3,231,890    3,214,130    2,211,190

   Additional paid-in capital
             Balance, beginning of year            388,090,930  167,430,347  166,654,305
             Common shares issued, net
              of issuance costs                      3,628,240  220,660,583      776,042
             Tax benefit related to employee
              stock options                          1,200,000            -            -

             Balance, end of year                  392,919,170  388,090,930  167,430,347

   Retained earnings
             Balance, beginning of year             81,099,357   49,399,461   37,546,460
             Dividends                              (6,444,654)  (3,100,636)  (2,648,898)
             Net earnings                           75,291,529   34,800,532   14,501,899
    
             Balance, end of year                  149,946,232   81,099,357   49,399,461

   Cumulative currency translation adjustment
             Balance, beginning of year                      -            -            -
             Net change                             (2,520,999)           -            -

             Balance, end of year                   (2,520,999)           -            -

   Total stockholders' equity, end of year        $543,576,293  472,404,417  219,040,998




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


<CAPTION>
                                                                 Year Ended December 31,
                                                           1997            1996         1995

   Cash flows from operating activities
      <S>                                              <C>             <C>           <C>
      Net earnings                                     $ 75,291,529    34,800,532    14,501,899
      Adjustments to reconcile net earnings to net
        cash provided by operating activities:
           Depreciation, depletion and amortization      85,306,868    43,361,029    38,089,783
           (Gain) loss on sale of assets                   (192,278)       (3,930)      273,238
           Deferred income taxes                         20,847,000    17,789,000     6,625,000
           Changes in assets and liabilities
             net of effects of acquisitions
             of businesses (Note 2):
               (Increase) decrease in:
                  Accounts receivable                   (17,835,233)  (15,470,528)    1,213,877
                  Inventories                              (344,286)     (176,286)      (70,937)
                  Prepaid expenses                         (116,932)     (466,617)      342,236
                  Other assets                             (874,496)   (1,032,653)      677,238
                Increase (decrease) in:
                  Accounts payable                        3,394,868     3,370,474      (430,736)
                  Income taxes payable                      445,493     3,341,377     1,364,070
                  Accrued expenses                        1,078,012       399,477      (221,550)
                  Revenues and royalties due to others    1,603,665       369,956    (1,793,909)
                  Long-term other liabilities               117,700       519,978       705,636

                  Net cash provided by operating
                    activities                          168,721,910    86,801,809    61,275,845

   Cash flows from investing activities
     Proceeds from sale of property and equipment         1,711,769     4,037,480     9,427,401
     Capital expenditures                              (130,468,542)  (98,854,846) (117,593,897)
     Payments made for acquisition of business                    -             -    (2,391,484)
     Increase in other assets                            (2,583,920)            -             -

                  Net cash used in investing
                    activities                        (131,340,693)   (94,817,366) (110,557,980)

   Cash flows from financing activities
     Proceeds from borrowings on revolving line
       of credit                                        1,847,750      29,000,000    52,000,000
     Principal payments on revolving line of credit    (9,843,750)   (164,000,000)   (7,000,000)
     Issuance of common stock, net of issuance costs    3,646,000         577,483       782,132
     Issuance of preferred securities of subsidiary
       trust, net of issuance costs                             -     144,665,205             -
     Dividends paid on common stock                    (6,444,654)     (3,100,636)   (2,648,898)
     Increase in long-term other liabilities (Note 3)   6,268,085       1,376,964     6,710,421

                   Net cash provided (used) by
                     financing activities              (4,526,569)      8,519,016    49,843,655

   Effect of exchange rate changes on cash               (191,654)              -             -

   Net increase in cash and cash equivalents           32,662,994         503,459       561,520

   Cash and cash equivalents at beginning of year       9,401,350       8,897,891     8,336,371

   Cash and cash equivalents at end of year         $  42,064,344       9,401,350     8,897,891

   See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1997, 1996 and 1995



   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 are primarily in the
   states of New Mexico,  Texas, Oklahoma, Wyoming and Louisiana.
   Effective   December  31,  1996,  Devon  began  operations  in
   Alberta, Canada.   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.

   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 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 and natural gas  liquids to oil at the ratio of
   one barrel ("Bbl") of oil to six thousand cubic
   feet  ("Mcf") of  natural  gas and  one  barrel of  oil to  42
   gallons of natural gas liquids.  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  approximately 97%  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.

   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  future  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  1997 and  1996, there  was one  purchaser,
   Aquila Energy Marketing Corporation ("Aquila"),  who accounted
   for over 10% of Devon's gas sales. Aquila accounted for 46% of
   Devon's 1997 gas  sales and  45% of  1996 gas  sales.   During
   1995,  there were two purchasers who accounted for over 10% of
   Devon's gas sales.   These two purchasers and their respective
   share  of  gas  sales  were:  Aquila  -  31%;  and  Enron  Gas
   Marketing, Inc. - 16%.  

   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.

   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.  The
   previously reported amounts for earnings per share assuming no
   dilution  (now replaced  by "basic  earnings per  share" under
   SFAS  No.  128) were  not  affected  for  any  prior  periods.
   Restated  "diluted" earnings  per share  were $0.01  per share
   less than the previously reported "earnings per share assuming
   full dilution"  for each of  the following periods:  the years
   1995  and 1994 and the  second and third quarters  of 1996 (as
   disclosed in Note 15).

               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
   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 tables  reconcile the  net earnings
   and  common shares  outstanding  used in  the calculations  of
   basic and diluted net  earnings per share for the  years 1997,
   1996 and 1995.
<TABLE>
<CAPTION>
                                                                                    Net
                                                                     Common      Earnings
                                                        Net          Shares         Per
                                                      Earnings     Outstanding     Share

   Year ended December 31, 1997:

     <S>                                            <C>             <C>            <C>
              Basic earnings per share                       $75,291,529     32,215,745     2.34

     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 $3,853,000)                                6,025,955       4,901,507

       Potential common shares issuable upon
       the exercise of employee stock options                -         408,477

       Diluted earnings per share                  $81,317,484      37,525,729     2.17

   Year ended December 31, 1996:

     Basic earnings per share                       34,800,532      22,159,507     1.57

     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)                       2,997,779        2,383,793

       Potential common shares issuable upon
       the exercise of employee stock options               -          254,352

       Diluted earnings per share                 $37,798,311       24,797,652     1.52

   Year ended December 31, 1995:

       Basic earnings per share                    14,501,899       22,073,550     0.66

       Dilutive effect of potential common
       shares issuable upon the exercise
       of employee stock options                            -          130,621

       Diluted earnings per share                 $14,501,899       22,204,171     0.65

</TABLE>

   Dividends

               Dividends on  common stock  were paid in  1995 and
   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.

   Fair Value of Financial Instruments

               Devon's only  financial instruments for  which the
   fair  value differs materially from the carrying value are the
   interest  rate  swap   discussed  in  Note  7  and  the  Trust
   Convertible  Preferred Securities  discussed in  Note 9.   The
   fair  value and  the carrying  value for  all other  financial
   instruments  (cash  and   equivalents,  accounts   receivable,
   accounts payable  and long-term debt) are approximately equal.
   Such equality is due  to the short-term nature of  the current
   assets and liabilities  and the fact  that the interest  rates
   paid  on Devon's long-term debt  are set for  periods of three
   months or less.

   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.

   Reclassifications

               Certain  items in  the 1996 and  1995 consolidated
   balance  sheets  and  statements   of  cash  flows  have  been
   reclassified to correspond with the 1997 presentation.

   2.          Acquisitions and Pro Forma Information

               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.)

               On  December 18,  1995, Devon  acquired additional
   interests  in  certain of  its  Wyoming  oil  and natural  gas
   properties   and  a   gas  processing   plant  (the   "Worland
   Properties") for approximately $50.3 million.  The acquisition
   was  primarily funded  with $46.0  million of  borrowings from
   Devon's  credit lines.    Approximately $46.3  million of  the
   purchase price  was allocated to  proved oil, gas  and natural
   gas liquids  reserves  and  the plant.    The  remaining  $4.0
   million  of the  purchase price  was allocated  to undeveloped
   leasehold. 

   Pro Forma Information (Unaudited)

               The 1996 acquisition of the KMG-NAOS Properties as
   described  above was accounted  for by the  purchase method of
   accounting   for  business  combinations.    Accordingly,  the
   accompanying  1996 consolidated  statement of  operations does
   not include any revenues or  expenses associated with the KMG-
   NAOS Properties.  Following are Devon's  pro forma results for
   1996  assuming  the  acquisition  of  the KMG-NAOS  Properties
   occurred on January 1, 1996:
<TABLE>
<CAPTION>
                                                                             
                                                                    1996

                  Revenues
                     <S>                                        <C>
                     Oil sales                                  $148,337,000
                     Gas sales                                   125,092,000
                     Natural gas liquids sales                    19,081,000
                     Other                                         4,674,000

                        Total revenues                           297,184,000

                  Costs and expenses
                     Lease operating expenses                     58,384,000
                     Production taxes                             20,167,000
                     Depreciation, depletion and amortization     78,310,000
                     General and administrative expenses          14,101,000
                     Interest expense                              5,277,000
                     Distributions on preferred securities
                       of subsidiary trust                         4,753,000

                        Total costs and expenses                 180,992,000

                  Earnings before income taxes                   116,192,000

                  Income tax expense
                     Current                                      14,023,000
                     Deferred                                     32,721,000

                        Total income tax expense                  46,744,000

                  Net earnings                                  $ 69,448,000

                  Net earnings per average common
                   share outstanding:
                     Basic                                            $2.16
                     Diluted                                          $2.09

                  Weighted average common shares
                    outstanding - basic                          32,086,310

                  Production data
                     Oil (Barrels)                                7,241,000
                     Gas (Mcf)                                   70,925,000
                     Natural gas liquids (Barrels)                1,304,000
</TABLE>

               The  1995  acquisition of  the  Worland Properties
   described above  was accounted for  by the purchase  method of
   accounting  for  business  combinations.     Accordingly,  the
   accompanying  consolidated statements  of  operations  do  not
   include  any  revenues  or  expenses related  to  the  Worland
   Properties  prior to the  closing date  of December  18, 1995.
   Following  are Devon's  pro  forma 1995  results assuming  the
   acquisition  of KMG-NAOS Properties and the Worland Properties
   both occurred on January 1, 1995:
<TABLE>
<CAPTION>
                                                            1995
                                                     Pro Forma Effect of
                                    Devon          KMG-NAOS        Worland         Devon
                                  Historical      Properties      Properties     Pro Forma

    <S>                          <C>              <C>             <C>           <C>
    Total revenues               $113,303,000     108,279,000     5,349,000     226,931,000
    Net earnings                  $14,502,000      14,335,000    (1,405,000)     27,432,000
    Net earnings per share:
      Basic                             $0.66                                          0.86
      Diluted                           $0.65                                          0.85
</TABLE>

   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").    These coal  seam gas  properties
   represented Devon's largest oil and gas reserve position as of
   December 31, 1994.   The properties' estimated reserves  as of
   year-end 1994  were 199.2 billion cubic feet ("Bcf") of natural
   gas, or 31% of  Devon's  633.2  equivalent  Bcf of  combined  oil
   and natural  gas reserves.    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
   1997  were equal to approximately $1.05 per million Btu ("MMBtu").

               The   San   Juan   Basin    Transaction   involves
   approximately  186.2 Bcf, or  93%, of  the 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,  1997, 1996 and 1995,  Devon received
   $11.4  million, $11.5 million and $13.9 million, respectively,
   related to the credits.  Of these amounts, $8.5 million, $10.3
   million  and $12.8  million  were recorded  as additional  gas
   sales in 1997, 1996 and  1995, respectively, and $2.9 million,
   $1.2  million and $1.1 million were recorded as an addition to
   liabilities in 1997, 1996 and 1995, respectively, as discussed
   in the following paragraph.   Based on the reserves  estimated
   at December 31,  1997, and an assumed  annual inflation factor
   of  2%,  Devon  estimates it  will  receive  total  tax credit
   payments of approximately $49 million from 1998 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 eventually
   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, 1997,  1996 and 1995, $2.9  million, $1.2 million
   and $1.1  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  in return  for Devon  agreeing  not to  exercise its
   option  on the remaining 80% of the properties through the end
   of  1997.   (This agreement  does not  limit Devon's  right to
   exercise its option in 1998 or beyond.)  The $5.3 million that
   Devon received, net of  the $1.9 million paid for  the partial
   repurchase,  was added  to the  repurchase liability  in 1997.
   The repurchase liability totaled  $14.2 million at the  end of
   1997.

               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  $14.2  million  of  other
   liabilities recorded as of year-end 1997, does not include any
   amount related to such reserves.

   4.          Supplemental Cash Flow Information

               Cash payments for interest  in 1997, 1996 and 1995
   were  approximately  $0.6  million,  $5.5  million  and   $6.7
   million, respectively.   Cash payments for  federal, state and
   foreign income taxes in 1997, 1996 and 1995 were approximately
   $25.0 million, $3.4 million and $2.2 million, respectively.

               The  1996 acquisition  of the  KMG-NAOS Properties
   involved non-cash consideration as presented below:

<TABLE>
      <S>                                          <C>
      Value of common stock issued                 $221,576,040
      Liabilities assumed                             3,098,691
      Deferred tax liability created                 30,308,000

      Fair value of assets acquired                $254,982,731
</TABLE>

   5.          Accounts Receivable

               The components of accounts receivable included the
   following:

<TABLE>
<CAPTION>
                                                                 
                                                          December 31,
                                              1997           1996            1995

      Oil, gas and natural gas liquids
         <S>                              <C>             <C>           <C>
         revenue accruals                 $32,643,633     24,200,047    11,169,313
     Joint interest billings               11,742,554      4,318,764     2,962,037
     Other                                  3,521,618      1,461,495       493,945

                                           47,907,805     29,980,306    14,625,295
     Allowance for doubtful accounts         (400,000)      (400,000)     (225,000)

     Net accounts receivable              $47,507,805     29,580,306    14,400,295
</TABLE>

   6.     Property and Equipment

     Property and equipment included the following:
<TABLE>
<CAPTION>
                                                                 
                                                           December 31,
                                             1997             1996             1995

     Oil and gas properties:
          <S>                           <C>                <C>             <C>
          Subject to amortization       $1,024,624,931     899,827,749     604,227,702
          Not subject to amortization:
               Acquired in 1997              9,476,111               -               -
               Acquired in 1996             27,906,918      35,141,800               -
               Acquired in 1995              3,916,088       5,034,942       5,635,170
               Acquired in 1994                870,664       1,001,291       1,001,427
               Acquired in 1993              4,026,995       5,204,995       5,556,977
               Acquired in 1992              7,814,255       8,113,899       8,257,985

          Accumulated depreciation,
            depletion and amortization    (361,055,425)   (278,923,340)   (237,385,785)

              Net oil and gas properties   717,580,537     675,401,336     387,293,476

      Other property and equipment          24,684,540      20,481,080       6,758,643

      Accumulated depreciation and
        amortization                       (4,462,297)      (3,036,070)     (2,233,382)

              Net other property and
                equipment                  20,222,243       17,445,010       4,525,261

      Property and equipment, net of
          accumulated depreciation,
          depletion and amortization   $  737,802,780      692,846,346     391,818,737
</TABLE>
Depreciation, depletion and amortization expense consisted of the following
components:
<TABLE>
<CAPTION>
                                                          Year Ended December 31,
                                                     1997           1996           1995

     Depreciation, depletion and amortization
       <S>                                       <C>             <C>            <C>
       of oil and gas properties                 $82,413,245     41,537,555     36,639,753
     Depreciation and amortization of other
       property and equipment                      2,328,461      1,337,420      1,045,978
     Amortization of other assets                    565,162        486,054        404,052

          Total expense                          $85,306,868     43,361,029     38,089,783
</TABLE>

   7.     Long-term Debt

     Devon has long-term lines of credit pursuant to which it can
   borrow up to an amount determined by the banks based on  their
   evaluation of the assets and  cash flow (the "Borrowing Base")
   of Devon. The established Borrowing Base at December 31, 1997,
   was  $208 million.   Amounts borrowed  under the  credit lines
   bear interest  at various fixed  rate options which  Devon may
   elect  for periods up  to 90 days.   Such rates  are generally
   less than  the prime rate.  Devon may also elect  to borrow at
   the prime rate.   No  amounts were borrowed  under the  credit
   lines at the end of  1997.  The average interest rates  on the
   outstanding debt at the  end of 1996 and  1995 were 6.19%  and
   6.64%, respectively.   The loan agreements also  provide for a
   quarterly facility fee equal to .25% per annum.

     Debt  borrowed under  the  credit lines  is  unsecured.   No
   principal payments  are  required until  maturity  unless  the
   unpaid balance exceeds the  maximum loan amount.   The maximum
   loan  amount is equal to  the Borrowing Base  until August 31,
   2000.   Thereafter, the maximum loan amount will be reduced by
   8.33%  every three  months until  August 31,  2003.   The loan
   agreements contain  certain covenants and  restrictions, among
   which  are  limitations  on additional  borrowings  and annual
   sales  of  properties valued  at  more than  $25  million, and
   working capital  and net  worth maintenance requirements.   At
   December 31, 1997, Devon was in compliance with such covenants
   and restrictions.

     Devon also has a  demand revolving operating credit facility
   with  a  Canadian bank.   This  facility  is unsecured  and is
   utilized  for general  corporate purposes  related to  Devon's
   Canadian  operations.   The credit  line totals  $12.5 million
   Canadian dollars, and interest is charged at the bank's  prime
   rate for  loans to Canadian  customers.  Amounts  borrowed are
   due on demand.   However, due to Devon's sources  of long-term
   debt  described  above,  amounts  borrowed   pursuant  to  the
   Canadian credit  line are expected  to be classified  as long-
   term  debt.   No  amounts were  borrowed against  the Canadian
   credit line at year-end 1997 or 1996.

     Devon entered into an interest rate swap  agreement in June,
   1995,  to hedge  the  impact of  interest  rate changes  on  a
   portion of its  long-term debt.   The notional  amount of  the
   swap agreement was  $75 million,  and the other  party to  the
   agreement  was one of Devon's lenders.  The swap agreement was
   accounted  for as a hedge.  On  July 1, 1996, Devon terminated
   the interest rate swap  agreement for a gain of  $0.8 million.
   This gain  is  being  recognized  ratably as  a  reduction  to
   interest expense during the  period from July 1, 1996  to June
   16,  1998 (the  original  expiration date  of the  agreement).
   Approximately $0.4 million of the gain was recognized in 1997,
   and $0.2 million  was recognized in 1996.   The fair value  of
   the interest rate swap as of December 31, 1995 was a liability 
   of  approximately $1.4 million.  The interest rate swap had no
   carrying  value  in  the accompanying  consolidated  financial
   statements.

     See  Note  9  for   a  description  of  certain  convertible
   debentures issued in 1996 to a Devon affiliate.

   8.     Income Taxes

     At December 31, 1997,  Devon had the following carryforwards
   available to reduce future federal and state income taxes:
<TABLE>
<CAPTION>
                                               Years of      Carryforward
     Types of Carryforward                    Expiration       Amounts   

     <S>                                     <C>             <C>
     Net operating loss - federal            2007 - 2008     $ 7,300,000
     Net operating loss - various states     1998 - 2011     $10,200,000
</TABLE>

     All  of  the  carryforward  amounts shown  above  have  been
   utilized for financial purposes to reduce deferred taxes.

     The  earnings  before income  taxes  and  the components  of
   income tax expense for  the years 1997, 1996 and  1995 were as
   follows:

<TABLE>
<CAPTION>
                                                                 
                                                Year Ended December 31,
                                         1997            1996            1995

     Earnings before income taxes:
          <S>                        <C>              <C>            <C>
          United States              $106,905,365     59,298,532     25,621,899
          Canada                       14,435,164              -              -

          Total                      $121,340,529     59,298,532     25,621,899

     Current income tax expense:
          Federal                     $18,659,000      6,147,000      4,155,000
          State                         2,521,000        562,000        340,000
          Canada                        4,022,000              -              -

          Total current tax expense    25,202,000      6,709,000      4,495,000

     Deferred income tax expense:
          Federal                      17,025,000     14,185,000      5,463,000
          State                         1,578,000      3,604,000      1,162,000
          Canada                        2,244,000              -              -

          Total deferred tax expense   20,847,000     17,789,000      6,625,000

     Total income tax expense         $46,049,000     24,498,000     11,120,000
</TABLE>

     Total income tax expense  differed from the amounts computed
   by applying the federal income tax rate to net earnings before
   income taxes as a result of the following:
<TABLE>
<CAPTION>
                                                                 
                                                Year Ended December 31,
                                               1997       1996       1995

     <S>                                        <C>        <C>        <C>
     Federal statutory tax rate                 35%        35%        35%
     Nonconventional fuel source credits        (1)         -         (1)
     State income taxes                          3          5          4
     Taxation on foreign operations              1          -          -
     Effect of San Juan Basin Transaction        -          2          4
     Other                                       -         (1)         1

     Effective income tax rate                  38%        41%        43%  
</TABLE>

     The tax effects  of temporary differences that  gave rise to
   significant   portions  of   the   deferred  tax   assets  and
   liabilities at December 31, 1997, 1996 and 1995 are  presented
   below:

<TABLE>
<CAPTION>
                                                                 
                                                                 December 31,
                                                       1997          1996         1995

     Deferred tax assets:
          <S>                                      <C>            <C>          <C>
          Net operating loss carryforwards         $ 2,909,000    5,314,000    6,082,000
          Statutory depletion carryforwards                  -      412,000    2,287,000
          Investment tax credit carryforwards           19,000       42,000       85,000
          Minimum tax credit carryforwards                   -    5,624,000    5,576,000
          Production payments                       18,504,000   19,685,000   24,770,000
          Other                                      2,932,000    2,613,000    1,966,000

               Total gross deferred tax assets      24,364,000   33,690,000   40,766,000
               Less valuation allowance                100,000      100,000      100,000

               Net deferred tax assets              24,264,000   33,590,000   40,666,000
     Deferred tax liabilities:
          Property and equipment, principally due
               to differences in depreciation, and
               the expensing of intangile drilling
               costs for tax purposes            (123,783,000) (113,111,000)  (74,369,000)
          Other                                    (1,521,000)            -             -

          Total deferred tax liabilities         (125,304,000) (113,111,000)  (74,369,000)

                 Net deferred tax liability     $(101,040,000)  (79,521,000)  (33,703,000)
</TABLE>

     As shown in  the above schedule, Devon has  recognized $24.3
   million  of net deferred tax  assets as of  December 31, 1997.
   Such  amount  consists  almost  entirely of  $2.9  million  of
   various carryforwards available to offset future income taxes,
   and  $18.5 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 2007,  and state net operating  loss carryforwards which
   expire primarily between 1999  and 2011.  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 1998  and 2001.   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 $100,000 valuation
   allowance has been recorded at  December 31, 1997, related  to
   depletion carryforwards acquired in a 1994 merger.

     The  $18.5  million  of   deferred  tax  assets  related  to
   production payments is offset by a portion of the deferred tax
   liability related  to the  excess financial basis  of property
   and equipment.   The income  tax accounting for  the San  Juan
   Basin  Transaction  described  in  Note  3  differs  from  the
   financial  accounting treatment  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  $18.5 million
   represents the tax effect of the  difference in accounting for
   the production  payment, less the  effect of the  taxable gain
   from the transaction which is being deferred and recognized on
   the installment basis for income tax purposes.

   9.     Trust Convertible Preferred Securities

     On July 10, 1996,  Devon, through its 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.    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.

     Devon estimates that the fair value of the TCP Securities as
   of December 31, 1997 and 1996 was approximately $218.8 million
   and  $196.6 million,  respectively,  as compared  to the  book
   value  of $149.5  million.   These fair  values were  based on
   quoted prices at which TCP Securities  were purchased and sold
   on December 31, 1997 and 1996.

   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.

     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, 1997, 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, 1997, 12 participants held the 251,100
   options outstanding  under the 1988 Plan,  and 23 participants
   held the 806,300 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.   Approximately 30 employees and  eight members of
   the board  of directors  were eligible  to participate in  the
   1997 Plan at year-end 1997.

     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, 1997, seven
   participants (all  of whom  are non-management members  of the
   Board of Directors) held  the 21,000 options outstanding under
   the 1997  Plan.   There were  1,979,000 options available  for
   future grants as of December 31, 1997.

     A summary of  the status of Devon's stock option plans as of
   December 31, 1995, 1996  and 1997, and changes during  each of
   the years then ended, is presented below:
<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, 1994       877,900     $18.947    485,000     $17.423

     Options granted                  219,000     $23.875
     Options exercised                (60,900)    $12.843
     Options forfeited                 (7,100)    $20.105

   Balance at December 31, 1995     1,028,900     $20.349    688,800     $19.744

     Options granted                  248,500     $32.358
     Options exercised                (75,400)    $12.909

   Balance at December 31, 1996     1,202,000     $23.299    823,500     $21.783

     Options granted                   54,000     $34.584
     Options exercised               (177,600)    $20.529

   Balance at December 31, 1997     1,078,400     $24.320   824,500      $23.257
</TABLE>

          The  weighted average  fair values  of options  granted
   during  1997, 1996  and 1995  were $13.74,  $12.97 and  $9.89,
   respectively.   The  fair  value  of  each  option  grant  was
   estimated for  disclosure purposes only  on the date  of grant
   using  the  Black-Scholes   Option  Pricing  Model   with  the
   following assumptions for  1997, 1996 and 1995,  respectively:
   risk-free  interest rates  of  6.3%, 6.3%  and 5.5%;  dividend
   yields  of 0.6%, 0.6% and  0.5%; expected lives  of five years
   for each period; and volatility of the price of the underlying
   common stock of 33.8%, 33.9% and 38.1%.

     The  following  table summarizes  information  about Devon's
   stock  options which  were outstanding,  and those  which were
   exercisable, as of December 31, 1997:
<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-$14       90,800     3.7 years     $ 9.677     90,800     $ 9.677
   $18-$21     150,300     6.9 years     $18.098    120,900     $18.106
   $23-$26     539,800     6.8 years     $23.799    451,000     $23.826
   $32-$37     297,500     9.0 years     $32.878    161,800     $33.138

             1,078,400     7.2 years     $24.320    824,500     $23.257
</TABLE>

     Had  Devon elected the fair value provisions of SFAS No. 123
   and recognized compensation expense based on the fair value of
   the  stock options  granted as  of their  grant  date, Devon's
   1997, 1996  and 1995 pro forma net earnings  and pro forma net
   earnings  per  share  would  have differed  from  the  amounts
   actually reported as  shown in the table below.  The pro forma
   amounts  shown  below do  not  include  the  effects of  stock
   options  granted  prior to  January 1,  1995.   The  pro forma
   effects  shown below may not be  representative of the effects
   reported in future years.
<TABLE>
<CAPTION>
                                        Year Ended December 31,  
                                    1997          1996          1995

     Net earnings:
          <S>                   <C>            <C>           <C>
          As reported           $75,291,529    34,800,532    14,501,899
          Pro forma             $74,564,309    34,016,571    13,540,052

     Net earnings per share:
          As reported:
               Basic                  $2.34         1.57           0.66
               Diluted                $2.17         1.52           0.65
          Pro forma:
               Basic                  $2.31         1.54           0.61
               Diluted                $2.15         1.49           0.61
</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.    Retirement Plans

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

     Effective  January 1,  1995,  Devon has  a separate  defined
   benefit retirement  plan (the "Supplementary  Plan") which  is
   non-contributory  and includes  only  certain employees  whose
   benefits  under the Basic  Plan are limited  by federal income
   tax regulations.  The  Supplementary Plan's benefits are based
   on the  employee's years of service and compensation.  Devon's
   funding  policy for  the  Supplementary Plan  is  to fund  the
   benefits as they become payable.  Rights to amend or terminate
   the Supplementary Plan are retained by Devon.

     The following  table sets forth the  aggregate funded status
   of the  Basic Plan and  related amounts recognized  in Devon's
   balance sheets:
<TABLE>
<CAPTION>
                                                                 
                                                                      December 31,           
                                                           1997           1996         1995

     Actuarial present value of benefit obligations:
          Accumulated benefit obligation:
            <S>                                        <C>            <C>          <C>
            Vested                                     $(4,630,000)   (3,619,000)  (3,500,000)
            Nonvested                                   (1,021,000)     (741,000)    (654,000)

            Total                                      $(5,651,000)   (4,360,000)  (4,154,000)

          Projected benefit obligation for service
             rendered to date                           (6,690,000)   (5,122,000)  (4,782,000)
     Plan assets at fair value, primarily investments
          in mutual funds                                6,036,000     5,022,000    4,227,000

     Plan assets less than projected benefit obligation   (654,000)     (100,000)    (555,000)
     Unrecognized prior service cost (benefit)            (105,000)     (131,000)    (154,000)
     Unrecognized net loss from past experience
       different from that assumed, and effects
       of changes in assumptions                         1,276,000       519,000      921,000

     Prepaid pension expense                          $    517,000       288,000      212,000
</TABLE>

            The  following table sets forth  the aggregate funded
   status   of  the  Supplementary   Plan  and   related  amounts
   recognized in Devon's balance sheets:
<TABLE>
<CAPTION>
                                                                 
                                                                       December 31,           
                                                            1997           1996          1995
     Actuarial present value of benefit obligations:
          Accumulated benefit obligation:
            <S>                                         <C>            <C>           <C>
            Vested                                      $(4,039,000)   (1,960,000)   (1,658,000)
            Nonvested                                      (237,000)     (279,000)     (255,000)

            Total                                        (4,276,000)   (2,239,000)   (1,913,000)

          Projected benefit obligation for service
            rendered to date                             (4,969,000)   (2,907,000)   (2,245,000)
     Plan assets at fair value                                    -             -             -
     Plan assets less than projected benefit
       obligation                                        (4,969,000)   (2,907,000)   (2,245,000)
     Unrecognized prior service cost                      2,078,000     1,235,000     1,354,000
     Unrecognized net loss from past experience
          different from that assumed, and effects
         of changes in assumptions                        1,172,000       446,000       185,000

     Accrued pension expense                             (1,719,000)   (1,226,000)     (706,000)
     Additional minimum liability                        (2,557,000)   (1,013,000)   (1,207,000)

     Total pension liability                            $(4,276,000)   (2,239,000)   (1,913,000)
</TABLE>
            The  $4.3  million,  $2.2  million  and  $1.9 million
   total  pension  liability  of  the Supplementary  Plan  as  of
   December 31,  1997, 1996 and 1995,  respectively, are included
   in   long-term   other   liabilities   on   the   accompanying
   consolidated   balance  sheets.      The  additional   minimum
   liabilities  of $2.6 million, $1.0 million and $1.2 million at
   year-end  1997, 1996  and  1995, respectively,  are offset  by
   intangible assets of the same amount.  These intangible assets
   are included in other assets on the balance sheets.

            Net pension  expense for Devon's  two defined benefit
   plans included the following components:
<TABLE>
<CAPTION>
                                                              Year Ended December 31,
                                                             1997       1996      1995

     <S>                                                 <C>          <C>       <C>
     Service cost - benefits earned during the period    $  706,000   557,000   362,000
     Interest cost on projected benefit obligation          747,000   569,000   446,000
     Actual return on plan assets                          (369,000) (453,000) (536,000)
     Net amortization and deferral                          177,000   231,000   345,000

     Net periodic pension expense                        $1,261,000   904,000   617,000
</TABLE>

     The weighted  average discount rate used  in determining the
   actuarial present value of the projected benefit obligation in
   1997, 1996  and 1995 was  7.0%, 7.5% and  7.25%, 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
   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
   $451,000, $188,000  and $170,000 for the  years ended December
   31, 1997, 1996 and 1995, respectively.

   12.    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 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 $1.3 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, 1997:
<TABLE>
<CAPTION>
          Year ending December 31,
              <S>                                         <C>
              1998                                        $  555,000
              1999                                           402,000
              2000                                           326,000
              2001                                            88,000
              2002                                            40,000

                 Total minimum lease payments required    $1,411,000
</TABLE>

     Total rental expense for all operating leases is as  follows
   for the years ended December 31:
<TABLE>
              <S>           <C>
              1997          $1,130,896
              1996          $  572,177
              1995          $  546,388 
</TABLE>

   13.    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,
                                                                1997          1996         1995
      Property acquisition costs:
            Proved, excluding deferred income
              <S>                                           <C>           <C>           <C>
              taxes                                         $10,997,000   199,655,000   47,316,000
            Deferred income taxes                             2,379,000    22,557,000            -

            Total proved, including deferred income taxes  $ 13,376,000   222,212,000   47,316,000

            Unproved, excluding deferred income taxes      $  8,734,000    29,673,000    4,529,000
            Deferred income taxes                              (100,000)    5,472,000            -

            Total unproved, including deferred income taxes   8,634,000    35,145,000    4,529,000

      Exploration costs                                     $19,169,000     2,708,000    7,174,000
      Development costs                                     $87,394,000    73,468,000   56,253,000
</TABLE>
<TABLE>
<CAPTION>
                                                                            Domestic                 
                                                                     Year Ended December 31,
                                                              1997           1996          1995
      Property acquisition costs:
            Proved, excluding deferred income
               <S>                                         <C>            <C>           <C>
               taxes                                       $10,891,000    150,546,000   47,316,000
            Deferred income taxes                            2,084,000     15,257,000            -

            Total proved, including deferred income taxes  $12,975,000    165,803,000   47,316,000

            Unproved, excluding deferred income taxes      $ 7,582,000     26,073,000    4,529,000
            Deferred income taxes                             (100,000)     5,472,000            -

            Total unproved, including deferred income taxes  7,482,000     31,545,000    4,529,000

      Exploration costs                                    $18,326,000      2,708,000    7,174,000
      Development costs                                    $79,943,000     73,468,000   56,253,000
</TABLE>
<TABLE>
<CAPTION>
                                                                             
                                                                             Canada                 
                                                                     Year Ended December 31,
                                                               1997           1996              1995
      Property acquisition costs:
            Proved, excluding deferred income
              <S>                                          <C>             <C>                   <C>
              taxes                                        $   106,000     49,109,000            -
            Deferred income taxes                              295,000      7,300,000            -

            Total proved, including deferred income taxes  $   401,000     56,409,000            -

            Unproved                                       $ 1,152,000      3,600,000            -
      Exploration costs                                    $   843,000              -            -
      Development costs                                    $ 7,451,000              -            -
</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 above  tables, were  $4.1
   million, $2.9 million and $2.7 million in the years 1997, 1996
   and 1995, 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  above  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 above 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.

   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,
                                                          1997            1996          1995

     <S>                                              <C>             <C>           <C>
     Oil, gas and natural gas liquids sales           $305,748,000    162,558,000   112,425,000
     Production and operating expenses                 (83,579,000)   (42,226,000)  (34,121,000)
     Depreciation, depletion and amortization          (82,413,000)   (41,538,000)  (36,640,000)
     Income tax expense                                (51,050,000)   (27,796,000)  (15,536,000)

     Results of operations for oil and gas
          producing activities                        $ 88,706,000     50,998,000    26,128,000

     Depreciation, depletion and amortization
          per equivalent barrel of production                $4.08           3.88          3.65
</TABLE>
<TABLE>
<CAPTION>
                                                                      Domestic             
                                                                Year Ended December 31,
                                                           1997          1996           1995

     <S>                                              <C>            <C>           <C>
     Oil, gas and natural gas liquids sales           $273,860,000   162,558,000   112,425,000
     Production and operating expenses                 (75,758,000)  (42,226,000)  (34,121,000)
     Depreciation, depletion and amortization          (73,091,000)  (41,538,000)  (36,640,000)
     Income tax expense                                (44,648,000)  (27,796,000)  (15,536,000)

     Results of operations for oil and gas
          producing activities                        $ 80,363,000    50,998,000    26,128,000

     Depreciation, depletion and amortization
          per equivalent barrel of production                $4.13          3.88          3.65
</TABLE>
<TABLE>
<CAPTION>
                                                                           Canada              
                                                                 Year Ended December 31,
                                                          1997               1996         1995

     <S>                                             <C>                       <C>           <C>
     Oil, gas and natural gas liquids sales          $ 31,888,000              -             -
     Production and operating expenses                 (7,821,000)             -             -
     Depreciation, depletion and amortization          (9,322,000)             -             -
     Income tax expense                                (6,402,000)             -             -

     Results of operations for oil and gas
          producing activities                       $  8,343,000              -             -

     Depreciation, depletion and amortization
          per equivalent barrel of production               $3.74              -             -
</TABLE>

     As previously discussed, the above tables 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.  Shown below are 1997  domestic and Canadian total
   revenues  and net  earnings,  including all  revenues and  all
   costs and expenses, as well as total assets.
<TABLE>
<CAPTION>
                                                               
                                                     Domestic       Canada        Total

   As of or for the Year Ended December 31, 1997:

              <S>                                  <C>            <C>          <C>
              Total revenues                       $278,834,000   34,306,000   313,140,000

              Net earnings                         $ 67,123,000    8,169,000    75,292,000

              Total assets                         $776,134,000   70,269,000   846,403,000

</TABLE>

   14.    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, 1997.
   Approximately  92%, 94%  and 92%,  of the  respective year-end
   1997, 1996  and 1995 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 1997
   and  1996  Canadian proved  reserves  were  calculated by  the
   independent petroleum consultants of AMH Group Ltd.
<TABLE>
<CAPTION>
                                                                Total                        
                                                                              Natural
                                                  Oil            Gas        Gas Liquids
                                                 (Bbls)         (Mcf)          (Bbls)

   <S>                                         <C>           <C>            <C>
   Proved reserves as of December 31, 1994     42,165,000    347,560,000    5,442,000
     Revisions of estimates                     1,127,000     (7,431,000)     535,000
     Extensions and discoveries                 2,959,000      9,645,000      472,000
     Purchase of reserves                       1,852,000     59,585,000    3,665,000
     Production                                (3,300,000)   (36,886,000)    (600,000)
     Sale of reserves                            (337,000)    (8,627,000)     (45,000)

   Proved reserves as of December 31, 1995     44,466,000    363,846,000    9,469,000
     Revisions of estimates                     2,365,000      4,359,000    1,096,000
     Extensions and discoveries                 3,680,000     14,849,000      852,000
     Purchase of reserves                      21,189,000    249,922,000    2,130,000
     Production                                (3,816,000)   (35,714,000)    (952,000)
     Sale of reserves                            (403,000)    (1,743,000)     (16,000)

   Proved reserves as of December 31, 1996     67,481,000    595,519,000   12,579,000
     Revisions of estimates                    (1,520,000)   (17,173,000)   1,614,000
     Extensions and discoveries                 8,517,000    106,608,000      301,000
     Purchase of reserves                       1,126,000        992,000       16,000
     Production                                (7,005,000)   (69,327,000)  (1,626,000)
     Sale of reserves                            (156,000)      (615,000)      (3,000)

   Proved reserves as of December 1997         68,443,000    616,004,000   12,881,000

   Proved developed reserves as of:
     December 31, 1994                         18,718,000    324,302,000    3,123,000
     December 31, 1995                         28,703,000    311,664,000    6,149,000
     December 31, 1996                         60,202,000    570,265,000   11,212,000
     December 31, 1997                         60,165,000    506,374,000   12,098,000
</TABLE>
<TABLE>
<CAPTION>
                                                             Domestic                      
                                                                             Natural
                                                 Oil            Gas        Gas Liquids
                                                (Bbls)         (Mcf)           (Bbls)

   <S>                                        <C>           <C>             <C>
   Proved reserves as of December 31, 1994    42,165,000    347,560,000     5,442,000
     Revisions of estimates                    1,127,000     (7,431,000)      535,000
     Extensions and discoveries                2,959,000      9,645,000       472,000
     Purchase of reserves                      1,852,000     59,585,000     3,665,000
     Production                               (3,300,000)   (36,886,000)     (600,000)
     Sale of reserves                           (337,000)    (8,627,000)      (45,000)

   Proved reserves as of December 31, 1995    44,466,000    363,846,000     9,469,000
     Revisions of estimates                    2,365,000      4,359,000     1,096,000
     Extensions and discoveries                3,680,000     14,849,000       852,000
     Purchase of reserves                     13,659,000    209,064,000     1,246,000
     Production                               (3,816,000)   (35,714,000)     (952,000)
     Sale of reserves                           (403,000)    (1,743,000)      (16,000)

   Proved reserves as of December 31, 1996    59,951,000    554,661,000    11,695,000
     Revisions of estimates                   (1,358,000)   (21,124,000)    1,531,000
     Extensions and discoveries                7,394,000     94,925,000       301,000
     Purchase of reserves                      1,126,000        992,000        16,000
     Production                               (6,055,000)   (61,015,000)   (1,468,000)
     Sale of reserves                           (156,000)      (615,000)       (3,000)

   Proved reserves as of December 31, 1997    60,902,000    567,824,000    12,072,000

   Proved developed reserves as of:
     December 31, 1994                        18,718,000    324,302,000     3,123,000
     December 31, 1995                        28,703,000    311,664,000     6,149,000
     December 31, 1996                        52,672,000    529,407,000    10,328,000
     December 31, 1997                        53,059,000    462,082,000    11,289,000
</TABLE>
<TABLE>
<CAPTION>
                                                            Canada
                                                                         Natural
                                                 Oil         Gas       Gas Liquids
                                               (Bbls)       (Mcf)        (Bbls)


   <S>                                               <C>          <C>         <C> 
   Proved reserves as of December 31, 1995           -            -           -
     Revisions of estimates                          -            -           -
     Extensions and discoveries                      -            -           -
     Purchase of reserves                    7,530,000   40,858,000     884,000
     Production                                      -            -           -
     Sale of reserves                                -            -           -

   Proved reserves as of December 31, 1996   7,530,000   40,858,000     884,000
     Revisions of estimates                   (162,000)   3,951,000      83,000
     Extensions and discoveries              1,123,000   11,683,000           -
     Purchase of reserves                            -            -           -
     Production                               (950,000)  (8,312,000)   (158,000)
     Sale of reserves                                -            -           -

   Proved reserves as of December 31, 1997   7,541,000   48,180,000     809,000

   Proved developed reserves as of
     December 31, 1996                       7,530,000   40,858,000     884,000
     December 31, 1997                       7,106,000   44,292,000     809,000
</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,
                                                1997            1996           1995

     <S>                                  <C>              <C>             <C>
     Future cash inflows                  $2,516,923,000   3,989,582,000   1,476,418,000
     Future costs:
          Development                        (88,292,000)    (54,133,000)    (52,327,000)
          Production                        (866,609,000) (1,071,913,000)   (496,279,000)
     Future income tax expense              (317,064,000)   (785,702,000)   (153,431,000)

     Future net cash flows                 1,244,958,000   2,077,834,000     774,381,000
     10% discount to reflect timing of
          cash flows                        (518,105,000)   (901,617,000)   (328,481,000)

     Standardized measure of
        discounted future net cash flows $   726,853,000   1,176,217,000     445,900,000

     Discounted future net cash
          flows before income taxes       $  913,073,000   1,621,992,000     534,248,000
</TABLE>
<TABLE>
<CAPTION>
                                                            Domestic
                                                          December 31,
                                               1997           1996             1995

     <S>                                 <C>              <C>             <C>
     Future cash inflows                 $2,304,602,000   3,712,956,000   1,476,418,000
     Future costs:
          Development                       (83,350,000)    (54,064,000)    (52,327,000)
          Production                       (806,130,000) (1,013,750,000)   (496,279,000)
     Future income tax expense             (269,880,000)   (713,182,000)   (153,431,000)

     Future net cash flows                1,145,242,000   1,931,960,000     774,381,000
     10% discount to reflect timing of
          cash flows                       (481,263,000)  (846,174,000)    (328,481,000)

     Standardized measure of
       discounted future net cash flows $   663,979,000  1,085,786,000      445,900,000

     Discounted future net cash
          flows before income taxes     $   820,448,000  1,486,603,000      534,248,000

</TABLE>
<TABLE>
<CAPTION>
                                                            Canada
                                                           December 31,
                                                1997          1996               1995

     <S>                                   <C>             <C>                        <S>
     Future cash inflows                   $212,321,000    276,626,000                -
     Future costs:
          Development                        (4,942,000)       (69,000)               -
          Production                        (60,479,000)   (58,163,000)               -
     Future income tax expense              (47,184,000)   (72,520,000)               -

     Future net cash flows                   99,716,000    145,874,000                -
     10% discount to reflect timing of
          cash flows                        (36,842,000)   (55,443,000)               -

     Standardized measure of
          discounted future net cash flows $ 62,874,000     90,431,000                -

     Discounted future net cash
          flows before income taxes        $ 92,625,000    135,389,000                -
</TABLE>

     Future cash inflows are computed by applying year-end prices
   (averaging   $16.93  per   barrel   of   oil,   adjusted   for
   transportation and  other charges,  $1.89 per  Mcf of  gas and
   $12.42 per barrel of natural gas liquids at December 31, 1997)
   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 $1.89 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 $35.2   million related to
   these tax credit payments from 1998 through 2002.  This amount
   has  been calculated  using the  assumption that  the year-end
   1997 tax credit rate of $1.05 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 pretax 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,
                                                        1997              1996           1995

          <S>                                      <C>                <C>             <C>
          Beginning balance                        $1,176,217,000     445,900,000     358,206,000
          Sales of oil, gas and natural gas
             liquids, net of production costs        (222,169,000)   (120,332,000)    (78,304,000)
          Net changes in prices and
             production costs                        (723,385,000)    519,456,000      60,498,000
          Extensions, discoveries, and improved
             recovery, net of future
             development costs                         52,566,000      42,522,000      22,308,000
          Purchase of reserves, net of future
             development costs                          7,696,000     576,234,000      50,000,000
          Development costs incurred during
             the period which reduced future
             development costs                         27,883,000      44,332,000      43,810,000
          Revisions of quantity estimates             (10,044,000)     40,905,000       7,397,000
          Sales of reserves in place                   (1,395,000)     (6,499,000)     (7,933,000)
          Accretion of discount                       162,199,000      53,425,000      39,821,000
          Net change in income taxes                  259,555,000    (357,427,000)    (48,347,000)
          Other, primarily changes in timing           (2,270,000)    (62,299,000)     (1,556,000)

          Ending balance                           $  726,853,000   1,176,217,000     445,900,000
</TABLE>

   15.    Supplemental     Quarterly     Financial    Information
   (Unaudited)

     Following  is a summary of  the unaudited interim results of
   operations for the years ended December 31, 1997 and 1996:
<TABLE>
<CAPTION>

                                                                    1997
                                       First         Second         Third        Fourth          Full
                                      Quarter        Quarter       Quarter       Quarter         Year

   Oil, gas and natural gas liquids
      <S>                            <C>            <C>           <C>           <C>           <C>
      sales                          $86,572,042    67,759,826    70,517,534    80,898,733    305,748,135
   Total revenues                    $87,899,646    69,651,782    72,860,503    82,727,937    313,139,868
   Net earnings                      $25,225,546    14,829,990    16,305,960    18,930,033     75,291,529
   Net earnings per share:
      Basic                                $0.78          0.46          0.51          0.59           2.34
      Diluted                              $0.71          0.44          0.47          0.54           2.17

</TABLE>
<TABLE>
<CAPTION>
                                                                    1996
                                        First        Second         Third        Fourth          Full
                                       Quarter       Quarter       Quarter       Quarter         Year

   Oil, gas and natural gas liquids
      <S>                            <C>            <C>           <C>           <C>           <C>
      sales                          $33,734,229    36,743,221    39,007,410    53,073,462    162,558,322
   Total revenues                    $34,048,060    37,298,613    39,473,680    53,196,531    164,016,884
   Net earnings                      $ 5,553,926     6,775,388     7,707,673    14,763,545     34,800,532
   Net earnings per share:
      Basic                                $0.25          0.31          0.35          0.66           1.57
      Diluted                              $0.25          0.30          0.34          0.59           1.52
</TABLE>

     The above amounts for diluted net earnings per share for the
   second  and third quarters of 1996 have been restated from the
   amounts  previously  reported  as  "net   earnings  per  share
   assuming full dilution" due to the adoption of SFAS No. 128 as
   discussed in Note 1.

<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, 1998.

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, 1998.

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, 1998.

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, 1998.
<PAGE>
                            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 42 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).

               3.1   Registrant's Certificate of Incorporation, as amended  
                     (incorporated by reference to Exhibit B to Registrant's
                     definitive Proxy Statement for its 1995 Annual Meeting
                     of Shareholders filed on April 21, 1995).

               3.2   Registrant's Certificate of Amendment of Certificate of
                     Incorporation (incorporated by reference to Exhibit 2 
                     to Registrant's Current Report on Form 8-K dated 
                     December 31, 1996).

               3.3   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   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).

                4.6  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)].

                4.7  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)].

                4.8  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)].

                4.9  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)].

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

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

               4.12  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)].

               4.13  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).

               4.14  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).

               10.1  Credit Agreement, dated August 30, 1996, among
                     Devon Energy Corporation (Nevada), as Borrower,
                     the Registrant and Devon Energy Operating Corporation,   as
                     Guarantors, NationsBank of Texas,  N.A., as
                     Agent, and NationsBank of Texas, N.A., Bank
                     One, Texas, N.A., Bank of Montreal, and First
                     Union  National Bank of North  Carolina, as
                     Lenders (incorporated by reference to Exhibit
                     10.1  to Registrant's Quarterly Report on Form
                     10-Q  for  the  quarter  ended  September  30,
                     1996).

               10.2  First Amendment to Credit Agreement, dated March 15,
                     1997, among Devon Energy Corporation (Nevada), as 
                     Borrower, the Registrant, as Guarantor, NationsBank of
                     Texas,  N.A.,  as  Agent  and  NationsBank  of
                     Texas,  N.A., Bank One, Texas, N.A.,  Bank  of
                     Montreal  and  First Union  National  Bank  of
                     North  Carolina (incorporated by reference  to
                     Exhibit 10.2 to Registrant's Quarterly  Report
                     on  Form 10-Q for the quarter ended March  31, 1997).

               10.3  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)].*

               10.4  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).*

               10.5  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).*

               10.6  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).*

               10.7  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).*

               10.8  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).*

               10.9  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).*

              10.10  Severance Agreement between Devon Energy Corporation
                     (Nevada), Devon Energy Corporation (Delaware)  and 
                     Mr. William T. Vaughn, dated December 3, 1992
                     (incorporated  by reference to  Exhibit  10.15
                     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), 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).*

              10.12  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).*

              10.13  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).*

              10.14  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).

              10.15  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).

              10.16  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)].

                 11  Computation of earnings per share

                 12  Computation of ratio of earnings to fixed charges

                 21  Subsidiaries of Registrant (incorporated by 
                     reference to Exhibit 21 to Registrant's  
                     Form 10-K for the year ended December 31, 1996).

               23.1  Consent of LaRoche Petroleum Consultants, Ltd.

               23.2  Consent of AMH Group, Ltd.

               23.3  Consent  of KPMG Peat  Marwick, LLP

               * Compensatory plans or arrangements.

               (b)   Reports on Form 8-K - No reports on Form  8-K
                     were  filed  during  the fourth  quarter of1997.
                     A Current Report on Form 8-K dated January 20, 1998,
                     was filed by the Registrant regarding year-end 1997
                     reserves, 1997 production and modifications to 1997
                     forward-looking information.  A Current Report on
                     Form 8-K dated January 27, 1998, was filed by the 
                     Registrant regarding 1998 forward-looking information.

<PAGE>
                      FORM S-8 UNDERTAKING


      For  the purposes of complying with the amendments  to  the
rules  governing  Form S-8 (effective July 13,  1990)  under  the
Securities  Act  of  1933,  the  undersigned  Registrant   hereby
undertakes as follows, which undertaking shall be incorporated by
reference to the Registrant's Registration Statement on Form  S-8
(No. 33-32378) and Registrant's Registration Statement on Form S-
8 (No. 33-67924).

          Insofar as indemnification for liabilities arising
     under  the  Securities Act of 1933 may be permitted  to
     directors,  officers  and controlling  persons  of  the
     Registrant  pursuant  to the foregoing  provisions,  or
     otherwise, the Registrant has been advised that in  the
     opinion of the Securities and Exchange Commission  such
     indemnification is against public policy  as  expressed
     in  the  Act and is, therefore, unenforceable.  In  the
     event  that  a  claim for indemnification against  such
     liabilities  (other than the payment by the  Registrant
     of  expenses incurred or paid by a director, officer or
     controlling person of the Registrant in the  successful
     defense  of any action, suit or proceeding) is asserted
     by  such  director,  officer or controlling  person  in
     connection  with  the securities being registered,  the
     Registrant  will, unless in the opinion of its  counsel
     the  matter  has been settled by controlling precedent,
     submit  to  a  court  of appropriate  jurisdiction  the
     questions whether such indemnification by it is against
     public  policy  as expressed in the  Act  and  will  be
     governed by the final adjudication of such issue.
<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 13, 1998                By  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 13, 1998                By  John W. Nichols
                              John W. Nichols
                              Chairman of the Board and Director


March 13, 1998                By J. Larry Nichols
                              J. Larry Nichols
                              President, Chief Executive Officer
                              and Director


March 13, 1998                By William T. Vaughn
                              William T. Vaughn
                              Vice President - Finance


March 13, 1998                By Danny J. Heatly
                              Danny J. Heatly
                              Controller


March 13, 1998                By H. R. Sanders, Jr.
                              H. R. Sanders, Jr.
                              Director


March 13, 1998                By Luke R. Corbett
                              Luke R. Corbett, Director



March 13, 1998                By Thomas F. Ferguson
                              Thomas F. Ferguson, Director



March 13, 1998                By David M. Gavrin
                              David M. Gavrin, Director



March 13, 1998                By Michael E. Gellert
                              Michael E. Gellert, Director



March 13, 1998                By Tom J. McDaniel
                              Tom J. McDaniel, Director



March 13, 1998                By Lawrence H. Towell
                              Lawrence H. Towell, Director

<PAGE>
                        INDEX TO EXHIBITS

                                                        Page
2.1   Agreement    and   Plan   of   Merger    and
      Reorganization  by and among Registrant  and
      Devon   Energy   Corporation,   a   Delaware
      corporation, dated as of April 13, 1995            #

2.2   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                                   #

3.1   Registrant's  Certificate of  Incorporation,
      as amended                                         #

3.2   Registrant's  Certificate  of  Amendment  of
      Certificate of Incorporation                       #

3.3   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   Certificate  of  Designations  of  Series  A
      Junior  Participating  Preferred  Stock   of
      Registrant                                         #

4.6   Certificate  of  Trust  of  Devon  Financing
      Trust                                              #

4.7   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             #

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

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

4.10  Form   of   6   1/2%  Preferred  Convertible
      Securities  (included  as  Exhibit  A-1   to
      Exhibit 4.5 above)                                 #

4.11  Form    of   6   1/2%   Convertible   Junior
      Subordinated    Debentures   (included    in
      Exhibit 4.7 above)                                 #

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

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

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

10.1  Credit  Agreement  dated  August  30,  1996,
      among Devon Energy Corporation (Nevada),  as
      Borrower,  the Registrant and  Devon  Energy
      Operating    Corporation,   as   Guarantors,
      NationsBank  of Texas, N.A., as  Agent,  and
      NationsBank  of  Texas,  N.A.,   Bank   One,
      Texas,  N.A.,  Bank of Montreal,  and  First
      Union  National Bank of North  Carolina,  as
      Lenders                                            #

10.2  First Amendment to Credit Agreement dated March 15, 1997,
      among Devon Energy Corporation (Nevada), as Borrower, the
      Registrant, as Guarantor, NationsBank of Texas, N.A., as Agent
      and NationsBank of Texas, N.A., Bank One, Texas, N.A., Bank of
      Montreal and First Union National Bank of North Carolina    #

10.3  Devon  Energy Corporation 1988 Stock  Option
      Plan                                               #

10.4  Devon  Energy Corporation 1993 Stock  Option
      Plan                                               # 

10.5  Devon  Energy Corporation 1997 Stock  Option
      Plan                                               # 

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

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

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

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

10.10 Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware) and Mr.  William  T.
      Vaughn, dated December 3, 1992                     #

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

10.12 Employment Agreement between Registrant  and
      Duke R. Ligon, dated February 7, 1997              #

10.13 Supplemental  Retirement  Income   Agreement
      between  Devon Energy Corporation  (Nevada),
      Registrant and John W. Nichols, dated  March
      26, 1997                                           #

10.14 Sale  and  Purchase  Agreement  relating  to
      Registrant's San Juan Basin gas properties         #

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

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

11    Computation of earnings per share                 99

12    Computation  of ratio of earnings  to  fixed
      charges                                          100

21    Subsidiaries of Registrant                         #

23.1  Consent  of  LaRoche Petroleum  Consultants,
      Ltd.                                             101

23.2  Consent of AMH Group Ltd.                        102

23.3  Consent of KPMG Peat Marwick LLP                 103
____________________________________
#  Incorporated by reference.