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, 1995
                                 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             (I.R.S. Employer
                       of                          Identification No.)
          Incorporation or Organization)
           20 North Broadway, Suite 1500               73102-8260
              Oklahoma City, Oklahoma                  (Zip Code)
               (Address of Principal
               Executive Offices)

     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 28, 1996 was $459,567,965.   At such date
   22,111,896 shares of common stock were outstanding.

                       DOCUMENTS INCORPORATED BY REFERENCE
     Proxy statement for the 1996 annual meeting of stockholders - Part III

                            Page 1 of 81 total pages <PAGE>
 

<PAGE>

                         TABLE OF CONTENTS

                                                             Page

  PART I
    Item 1. Business  . . . . . . . . . . . . . . . . . .        3
    Item 2. Properties  . . . . . . . . . . . . . . . . .       10
    Item 3. Legal Proceedings . . . . . . . . . . . . . .       20
    Item 4. Submission of Matters to a Vote of Security Holders 20

  PART II
    Item 5. Market for Registrant's Common Equity
      and Related Stockholder Matters . . . . . . . . . .       20
    Item 6. Selected Financial Data . . . . . . . . . . .       22
    Item 7.  Management's Discussion  and Analysis  of Financial
       Condition and Results of Operations . . . . . . . . . . .24
    Item 8. Financial Statements and Supplementary Data .       37
    Item 9. Changes  in  and Disagreements  with Accountants  on
       Accounting and Financial Disclosure  . . . . . . . . . . 71

  PART III
    Item 10. Directors and Executive Officers of the Registrant 71
    Item 11. Executive Compensation . . . . . . . . . . .       71
    Item 12. Security Ownership  of Certain Beneficial Owners and
       Management  . . . . . . . . . . . . . . . . . . . . . .  71
    Item 13. Certain Relationships and Related Transactions     71

  PART IV
    Item 14. Exhibits, Financial Statement Schedules,
      and Reports on Form 8-K . . . . . . . . . . . . . .       72

                            DEFINITIONS

                       As used in this document:

                    "Mcf" means thousand cubic feet
                    "MMcf" means million cubic feet
                     "Bcf" means billion cubic feet
                           "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>
                     FORWARD LOOKING STATEMENTS

       This document  contains  "forward looking  statements"  as
  defined  by  the  Securities Litigation  Reform  Act  of  1995.
  Unless  otherwise  specifically  identified,  forward   looking
  statements are  identified by  an asterisk  (*) preceeding  and
  following  each  such  statement.    Foward  looking statements
  should be  read in conjunction  with the cautionary  statements
  included in  this document, including  those found under  "Item
  2.    Properties -  Proved  Reserves and  Estimated  Future Net
  Revenues" and  "Item 7.   Management's Discussion and  Analysis
  of  Financial Condition  and Results  of  Operations -  Capital
  Expenditures,  Capital   Resources   and   Liquidity   -   1996
  Estimates."

                               PART I


   ITEM 1. BUSINESS

         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.  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
   405/235-3611).

         Devon's oil and gas properties are its  primary assets and the source
   of  its cash flow and earnings.  Devon owns interests in  900 producing oil
   and gas  properties in ten states. At December 31,  1995, Devon's estimated
   proved reserves were  363.8 Bcf of natural gas, 44.5  MMBbls of oil and 9.5
   MMBoe  of NGLs,  or  114.6 MMBoe  in  total. Ninety-eight  percent  of such
   reserves are located in New Mexico, Wyoming, Texas, Oklahoma and Louisiana.

         During 1988, Devon expanded its capital base with its first  issuance
   of  common stock to the  public and began a  substantial expansion program.
   Devon has utilized a two-pronged strategy of acquiring producing properties
   and  engaging primarily  in  development drilling  and  limited exploration
   activities. During  the eight  years  ended December  31, 1995,  Devon  has
   drilled  605 new  wells, 581 of  which were  producers, and  consummated 15
   significant  acquisitions. During  this  same period,  total  capital costs
   incurred  (including  acquisition  and drilling  costs)  aggregated  $535.0
   million. Reserve  additions were 538.1  Bcf of gas, 58.2 MMBbls  of oil and
   11.2 MMBoe of  NGLs. These additions, minus production and  property sales,
   resulted  in  reserves  increasing by  a  factor  of  fourteen  during  the
   eight-year period.

         Devon's single largest  reserve position relates to its  interests in
   two  federal units  in  northwest  New Mexico:  the Northeast  Blanco  Unit
   ("NEBU") and the San Juan 32-9 Unit  Fruitland Coal Participating Area (the
   "32-9 Unit").  These "state-of-the-art" projects produce natural gas from a
   nonconventional source:  the Fruitland Coal formation. With  NEBU, the 32-9
   Unit and  certain minor properties,  Devon's property holdings  in the  San
   Juan  Basin  account  for 29.4  MMBoe,  or  26%,  of  Devon's  total proved
   reserves.  Devon's interest in coal seam production  is part  of a
   transaction the  Company entered  into effective January 1,  1995.
   See "-  1995 Transactions -  San Juan Basin Transaction" below.

         Devon's  second  largest  reserve  position  is related  to  its 100%
   working interest in the Grayburg-Jackson field in the southeast New  Mexico
   portion of the  Permian Basin. Devon is in the  second year of an extensive
   infill drilling program and waterflood project expected to be completed  in
   1997.  *Total  development  costs  for  both the  infill  drilling  and the
   waterflood projects  are estimated  to be  approximately $60 million,  $5.8
   million of which was spent in 1994 and $30.1 million of which  was spent in
   1995.*  As  of December 31, 1995,  the Grayburg-Jackson Field accounted for
   26.4 MMBoe, or 23%, of Devon's total proved reserves.  Approximately 52% of
   total proved reserves  for this field are classified as  proved undeveloped
   and are associated with the infill/waterflood program.  

         Devon also owns  other significant interests in the Permian  Basin of
   western Texas and southeastern New  Mexico. These interests are in a number
   of different fields in the Basin, none of which, individually, accounts for
   more  than  5%  of total  reserves.  However,  these  holdings  are  highly
   concentrated in  a  relatively  small  geographic  area  and  possess  many
   operational  and geologic  similarities. Since  1987, Devon  has made  four
   separate  acquisitions  of  properties  in  the Permian  Basin.  With these
   acquisitions, Devon gained significant developed  and undeveloped leasehold
   acreage. The multi-objective  nature (several potential producing zones) of
   the Permian  Basin will  continue  to provide  Devon with  exploration  and
   development  opportunities which  could further expand its  reserves. As of
   year-end 1995, the Permian Basin properties other than the Grayburg-Jackson
   Field accounted for 28% of Devon's total proved reserves.

         1995 Transactions

         Worland  Acquisition  -   In  December,  1995,  Devon  completed  the
   acquisition  of  a  group of  oil  and natural  gas  properties  and a  gas
   processing plant located in north-central Wyoming (the "Worland Property").
   Combined with the  small interest Devon previously owned, this  property is
   now Devon's third largest, accounting for about 14% of the  Company's total
   proved reserves.  

         The properties  acquired in  1995  were purchased  from a  major  oil
   company for $50.3 million.   All of the properties are located on a 25,000-
   acre federal unit in Big Horn and Washakie Counties, Wyoming.  Of the $50.3
   million total purchase  price, $46.3 million was allocated to  38 producing
   wells, 16 proved undeveloped locations and a natural gas processing  plant.
   The acquired assets had total estimated proved reserves of 15.3 MMBoe as of
   year-end 1995.   The remaining $4  million purchase price was  allocated to
   undeveloped leases on the unit.   *Devon expects to invest an additional $9
   million in  1996  to  further  develop  the  property,  including  drilling
   additional wells and upgrading the gas processing plant.*

         In  early 1996 Devon  increased its interest in  the Worland Property
   through several  smaller acquisitions  totaling $7  million.   After  these
   smaller  acquisitions,  the Company  now owns  an  approximate  98% working
   interest  in the proved properties and 100% of the gas processing plant and
   15,500  acres of undeveloped  leases.   Because the Worland Field  has many
   potentially  productive  producing  zones,  the  acreage  will provide  the
   Company  with many  exploration and  development opportunities  which could
   increase reserves.  


<PAGE>

         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, i.e., NEBU  and the 32-9
   Unit,  (the "San Juan Basin Transaction").  *The  effect of the transaction
   is that the price the Company receives for its coal seam gas production has
   increased by  $0.61 per  Mcf from  1995 through the  year 2002.   Based  on
   current  estimates  of  coal  seam  gas  production,  the  San  Juan  Basin
   Transaction will  result in  approximately $11  million of  additional  gas
   revenues  in  1996  and  a  total  of  $71 million  over  the  life  of the
   transaction  (including $12.8  million received  in 1995).*   See  "Item 2.
   Properties.   Significant Properties  -  San Juan  Basin -  San Juan  Basin
   Transaction" for a more detailed description of this transaction.

   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 1996 will be
   concentrated in the Permian  Basin, Rockies and  Gulf Coast regions of  the
   U.S.

         The  following tables  set forth  Devon's drilling  results for  1988
   through 1995.
<TABLE>
<CAPTION>
                                Development Wells

                      Gross (1)                    Net (2)       
               Productive   Dry   Total  Productive  Dry    Total
               ----------   ---   -----  ----------  ---    -----
   <C>            <C>        <C>    <C>   <C>       <C>    <C>

   1988            23        0       23     4.13       0     4.13
   1989            32        1       33     7.02    0.01     7.03
   1990            80        0       80    19.37       0    19.37
   1991            22        1       23     1.62    0.11     1.73
   1992            53        2       55     7.84    0.12     7.96
   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
                  ---       ---     ---   ------    ----   ------
                  563       12      575   271.64    2.21   273.85

(1)  A gross well is a well in which Devon owns an interest.
(2)  Net wells are the sum of Devon's working interests in gross wells.
</TABLE>

<TABLE>
<CAPTION>
                                Exploratory Wells
                      Gross (1)                    Net (2)       
               Productive   Dry   Total  Productive  Dry    Total
               ----------   ---   -----  ----------  ---    -----
   <C>              <C>      <C>     <C>    <C>     <C>      <C>

   1988             0        1        1        0    0.32     0.32
   1989             0        1        1        0    0.69     0.69
   1990             0        1        1        0    0.20     0.20
   1991             0        0        0        0       0        0
   1992             3        1        4     1.09    0.25     1.34
   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
                   --       --       --     ----    ----    -----
                   18       12       30     6.19    5.50    11.69

                                       

   (1) A gross well is a well in which Devon owns an interest.
   (2) Net wells are the sum of Devon's working interests in gross wells.
</TABLE>

         As of  December 31, 1995, Devon was participating in  the drilling of
   16 gross (11.29 net) development wells which are not  included in the table
   above. Through February  28, 1996, 11 gross (10.7  net) of these wells were
   completed as productive and the remaining wells were still in progress.

   Customers

         For the  year ended  December 31,  1995, two significant  purchasers,
   Aquila  Energy Marketing  Corporation ("Aquila")  and Enron  Gas Marketing,
   Inc. ("Enron"),  accounted for 31%  and 16%, respectively,  of Devon's  gas
   sales.   For the year ended  December 31, 1994, Aquila,  Enron and Meridian
   Oil Trading, Inc. ("MOTI") accounted for 21%, 19% and 18%, respectively, of
   Devon's gas  sales.  For  the year ended  December 31, 1993,  there was one
   significant  purchaser,  MOTI, which  accounted  for  approximately  39% of
   Devon's gas sales. Until September, 1995, MOTI was a significant  purchaser
   of Devon's NEBU coal seam gas production at  a market-sensitive price under
   the terms  of a five-year contract  entered into in  May, 1990.  Aquila and
   Enron purchase gas  from numerous Devon properties, including NEBU  and the
   32-9 Unit.  These purchases  are  primarily made  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 Gas Marketing

         Natural  Gas  Marketing.    Virtually  all  of  Devon's  natural  gas
   production is sold at variable, or "market-sensitive" prices.  Though exact
   percentages vary daily, approximately 9% of such natural  gas is sold under
   short-term contracts. The remaining 91% 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
   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  90   day  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.

         Oil Marketing.   Devon's oil production is  sold under both long- and
   short-term agreements at prices in the range  of field prices as posted  by
   certain crude  purchasers. Approximately 2% of  Devon's 1995 oil production
   was purchased by  its wholly-owned subsidiary, Devon Marketing Corporation,
   which also purchases oil  from third parties and resells the purchased  oil
   under contracts to refiners and others.

   Competition

         The  oil  and gas  business is  highly competitive.  Devon encounters
   competition  by major integrated  and independent oil and  gas companies in
   acquiring  properties  and  drilling  prospects,  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 have begun  to more effectively utilize natural gas  storage capacity
   by purchasing some of the winter load in the summer.

   Government Regulation

         The oil and  gas industry is extensively regulated by  federal, state
   and local authorities.  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.


<PAGE>

         Exploration  and  Production.    Devon's  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
   at NEBU, the  32-9 Unit, the  Worland Property  and many  of the  Company's
   leases in  southeast New Mexico, including  the Grayburg-Jackson Field, 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. The Mineral  Lands Leasing Act of 1920
   places limitations  on the  number of  acres of  federal lands that  may be
   leased  by any entity or person in any one state. Additionally, the Mineral
   Lands  Leasing  Act  of  1920  and  related  regulations  also  restrict  a
   corporation from holding  federal onshore  oil and gas leases  if stock  of
   such corporation is  owned by citizens of  foreign countries which are  not
   deemed  reciprocal under such  Act. Reciprocity depends, in  large part, on
   whether the laws of the foreign jurisdiction discriminate against a  United
   States citizen's ownership of rights to minerals in such jurisdiction.  The
   purchase  of shares  in Devon  by citizens of  foreign countries  with laws
   which are not deemed to  be reciprocal under such Act could  have an impact
   on Devon's  ownership of federal leases.

         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  deleterious substances.  However,  100% coverage  is  not maintained
   concerning  any environmental  claim, and  no coverage  is maintained  with

<PAGE>

   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's unreimbursed expenditures  in 1995  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 the 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.

         No Price  Controls on Liquid  Hydrocarbons.  There  are currently  no
   price controls on crude oil, condensate or NGLs.

   Employees

         As of  December 31, 1995,  Devon's staff consisted  of 203  full-time
   employees,  including 15 professionals  in engineering, 6 in  geology, 5 in
   the land  department, 4 in oil and gas marketing, 30 in accounting and data
   processing,  7 in administration and other  support positions. In addition,
   through its affiliate, Blackwood & Nichols Co. A Limited Partnership, Devon
   employs  21 people,  including  3  operations engineers.  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  located  in  New Mexico,
   Wyoming, Texas,  Oklahoma and Louisiana.  These interests  entitle Devon to
   drill  for and  produce oil,  natural gas  and NGLs  from a  specific area.
   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  present value  thereof,  discounted  at 10%  per annum  ("10%  Present

<PAGE>

   Value"), as  of December  31,  1995. Approximately  92% of  Devon's  proved
   reserves  were estimated  by  LaRoche &  Associates,  independent petroleum
   engineers  ("LaRoche"). The remainder  of such  reserves were  estimated by
   Devon's  internal staff  of engineers. In  preparing their  estimates, both
   LaRoche  and 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). These  estimates correspond
   with the method used in presenting the  supplemental information on oil and
   gas  operations  in note  13 to  Devon's consolidated  financial statements
   included herein, except that federal income taxes otherwise attributable to
   such future net revenues have been disregarded in the presentation below.
<TABLE>
<CAPTION>

                                                    Total     Proved      Proved
                                                   Proved  Developed      Undeveloped
                                                 Reserves   Reserves <F1> Reserves <F2>
         <S>                                      <C>        <C>            <C>

         Oil (MBBls) . . . . . . . . . . . . . .   44,466     28,703         15,763
         Gas (MMcf)  . . . . . . . . . . . . . .  363,846    311,664         52,182
         NGLs (MBoe) . . . . . . . . . . . . . .    9,469      6,149          3,320
         MBoe <F3> . . . . . . . . . . . . . . .  114,576     86,797         27,779
         Pre-tax Future Net Revenue
             ($ thousands)<F4>                    927,812    667,994        259,818
         Pre-tax 10% Present Value
             ($ thousands)<F4>                    534,248    411,400        122,848


<PAGE>
<FN>

<F1> Proved  developed  reserves are  proved reserves that are expected to
     be recovered from  existing wells  with  existing  equipment  and
     operating methods.

<F2> 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
     recompletion, deepening or  new fluid  injection facilities.

<F3> 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  and  other  factors in  addition to
     relative energy content.

<F4> Estimated   future   net    revenue   represents estimated  future
     gross revenue  to be generated from the  production of proved reserves,
     net of estimated  production  and   future  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,  1995.  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
     $18.11 per  Bbl of oil, $1.35 per Mcf of  natural gas ($1.51
     per  Mcf  including  the   effect  of  the  San  Juan  Basin
     Transaction),  and  $12.73 per  Boe  of  NGLs.  These prices
     compare  to  benchmark  prices  of  $18.00  for  West  Texas
     Intermediate crude oil  and $2.10 for Texas Gulf  Coast spot
     gas.

</FN>
</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  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,  1995. 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.  Devon's total proved  reserves for the  years
  ended  December  31,  1988  through   1991  were  estimated  by
  LaRoche.  Approximately  88%,  95%,  91%  and  92%  of  Devon's
  reserves as  of the years  ended December 31,  1992, 1993, 1994
  and 1995, respectively, were estimated  by LaRoche. The balance
  of the  reserves were  estimated by  Devon's internal  staff of
  engineers.


<PAGE>

<TABLE>
<CAPTION>

                             Total Proved Reserves                Proved Developed Reserves
                      -------------------------------------    ------------------------------------
 As of December 31,   Oil (MBbls)   Gas (MMcf)  NGLs (MBoe)    Oil(MBbls)   Gas (MMcf)   NGLs(MBoe)
   <S>                   <C>          <C>      <C>             <C>          <C>        <C>

    1988                  5,590        98,388      - <F1>        4,203       65,503        - (1)
    1989                  4,800       149,761      - <F1>        3,688       82,086        - (1)
    1990                  4,058       169,473      - <F1>        3,456      163,364        - (1)
    1991                  3,798       191,642      - <F1>        3,179      191,360        - (1)
    1992                 16,349       263,598  1,011            13,823      249,154      797
    1993                 14,897       369,254  1,854            11,548      355,536    1,751
    1994                 42,165       347,560  5,442            18,718      324,302    3,123
    1995                 44,466       363,846  9,469            28,703      311,664    6,149

<FN>

<F1> Minor quantities of NGLs are included in oil reserves.
</FN>
</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  five years ended  December 31,  1995, is  set
  forth in "Item 6. Selected Financial Data."

  Well Statistics

       As  of December  31, 1995,  Devon had  interests in  4,024
  producing wells, of  which 2,903 gross (793 net) were oil wells
  and 1,121  gross (430 net)  were natural gas  wells. 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.

  Leasehold

       The  following  table  sets  forth Devon's  developed  and
  undeveloped oil and gas lease acreage as of December 31, 1995.














<PAGE>

<TABLE>
<CAPTION>
                                     Developed               Undeveloped   
                               ----------------------   ----------------------
                               Gross<F1>     Net<F2>    Gross<F1>      Net<F2>
        <S>                     <C>        <C>         <C>         <C>

        Arkansas                     40         40           0           0
        California                    0          0       5,098         199
        Colorado                  1,279        121       8,382       5,725
        Kansas                    1,665        901         160           7
        Louisiana                10,214      4,537      18,059       8,952
        Montana                       0          0       3,828       1,312
        New Mexico               90,293     50,154      56,532      39,400
        North Dakota                  0          0       2,715         817
        Oklahoma                 68,789     32,271      24,992      11,176
        Texas                   145,582     76,274     111,014      70,369
        Utah                        277        134         680         453
        West Virginia             4,991      3,737         609         144
        Wyoming                  43,437     36,392      33,855      23,530
                                -------    -------     -------     -------
                                366,567    204,561     265,924     162,084
<FN>
<F1>  Gross acres are the total number of acres in which Devon owns a
      working interest.

<F2>  Net  refers to  gross  acres multiplied  by  Devon's fractional
      working interests therein.

</FN>
</TABLE>


   Significant Properties

         The following table sets  forth information on  the most  significant
   geographic areas in which Devon's properties are located as of December 31,
   1995.




























<PAGE>
<TABLE>
<CAPTION>
                                                                                           10% Present
                                                                                            Value <F3>  10% Present
                              Oil(MBbls)   Gas(MMcf)    NGLs(MBoe)  MBoe<F1>    MBoe%<F2>    ($000)     Value% <F4>
<S>                           <C>           <C>          <C>         <C>       <C>          <C>          <C>
San Juan Basin:
Northwest New Mexico
  Northeast Blanco Unit            5        119,035         25        19,869    17.3%       $ 75,531<F5>  14.2%
  32-9 Unit                        0         56,741          0         9,457     8.3%         38,667<F6>   7.2%
  Other                            5            292          0            54       0             216       0
                                  --        -------         --        ------    -----       --------      -----
  Total                           10        176,068         25        29,380    25.6%       $114,414      21.4%

Permian Basin:
West Texas and
Southeast New Mexico
  Grayburg-Jackson Field      23,250          7,916      1,853        26,422    23.1%       $157,922      29.6%
  Other                       16,312         75,597      3,018        31,930    27.9%        161,184      30.1%
                              ------         ------      -----        ------    -----       --------      -----
  Total                       39,562         83,513      4,871        58,352    51.0%       $319,106      59.7%

Rocky Mountains:
Colorado and Wyoming
  Worland Unit                 1,913         62,563      3,707        16,047    14.0%       $ 51,559       9.7%
  Other                        1,348          3,278        362         2,256     2.0%          9,113       1.7%
                               -----         ------      -----        ------    -----       --------      -----
  Total                        3,261         65,841      4,069        18,303    16.0%       $ 60,672      11.4%

Mid-Continent:
Oklahoma and
Texas Panhandle                1,009         30,479        480         6,569     5.7%       $ 30,608       5.7%

All Other Properties             624          7,945         24         1,972     1.7%          9,448       1.8%
                              ------        -------      -----       -------   ------       --------     ------
Grand Total                   44,466        363,846      9,469       114,576   100.0%       $534,248     100.0%

<FN>
<F1>     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.

<F2>     Percentage which MBoe for the basin or region bears to total MBoe for
         all Proved Reserves.

<F3>     Determined in accordance  with SEC guidelines, except  that no effect
         is given to future income taxes.

<F4>     Percentage which present value for the basin or region bears to total
         present value for all Proved Reserves.

<F5>    Includes $28.1 million of  additional value attributable to San  Juan
        Basin Transaction through the year 2002.

<F6>    Includes  $16.3 million of additional value  attributable to San Juan
        Basin Transaction through the year 2002.

</FN>
</TABLE>

<PAGE>

       San Juan Basin.   Devon's single largest  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 historically been  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 can  now arguably  be considered  the
  largest gas  producing basin in  the U.S.   Production from the
  coal seams constitutes  almost all of Devon's reserves in these
  two units.  

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

       Northeast Blanco Unit.   Approximately 96%, or  114.6 Bcf,
  of Devon's proved reserves attributable  to NEBU are associated
  with the Fruitland coal seam formation.  The potential for coal
  seam gas production 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 through a Devon affiliate,
  Blackwood  & Nichols  Co. A  Limited  Partnership. 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.

       By  late  1990,  the  first  NEBU  coal  seam  wells  were
  connected to pipelines  and began producing.   Additional wells
  were  connected each  year  until  project completion  in  late
  1993.    Production increased  each  year  through 1994.    The
  following table shows Devon's net production from NEBU:

                      Year   Gas Production
                      ----   --------------
                      1990     1.0 Bcf
                      1991     8.7 Bcf
                      1992    17.5 Bcf
                      1993    18.2 Bcf
                      1994    18.7 Bcf
                      1995    16.2 Bcf
                              --------
                      Total   80.3 Bcf


<PAGE>

  As  the  table  above  illustrates,  NEBU  production  declined
  slightly, as expected,  in 1995. About 1.2 Bcf of the reduction
  is due to the San Juan Basin Transaction described below.   The
  remainder  of the reduced production is due to natural decline.
  *It is likely that production will decrease to  13 to 15 Bcf in
  1996   and  continue   a  modest   decline  thereafter   unless
  additional  development or  new technology  is  applied to  the
  property.*

       The  current reserve estimates at NEBU  assume that 55% to
  65%  of  the  coal  seam  gas  in  place  can  be  economically
  recovered through  the existing wells.   *Additional production
  and  recoverable  reserves  might  be   realized  by  continued
  reduction  in   operating  pressure  through   compression  and
  pipeline optimization, by  use of subsurface pumping  equipment
  to  remove  water, by  drilling additional  wells, or  by using
  enhanced recovery techniques, such as injecting carbon  dioxide
  or  nitrogen into the coal  formation, to  force additional gas
  to  the producing well  bores.*  Devon and  other owners in the
  San  Juan  Basin  are studying  and  experimenting  with  these
  various  options  to  determine  if  additional  recoveries are
  economically feasible.   *If such development projects  were to
  be undertaken by Devon, it  would likely result in  significant
  additional capital  expenditures and gas  reserves.*  (As  part
  of the  San Juan Basin  Transaction, Devon will  be entitled to
  75%  of any  reserves in  excess  of those  estimated to  be in
  place  at the time  of the transaction.   The  third party will
  pay  100%  of  the   capital  necessary  to  develop  any  such
  incremental reserves  for its  25% interest  in such  reserves.
  See " - San Juan Basin Transaction" below.)

       32-9  Unit.    The 32-9  Unit,  operated  by  Meridian Oil
  Production,  Inc.,   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,  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.  The
  current reserve  estimates assume that  20% to 30%  of the coal
  seam gas  in place  can be  economically recovered through  the
  existing wells.   *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. There is the possibility that some infill
  wells may be  drilled to accelerate production, if the State of
  New Mexico allows drilling on 160-acre  spacing rather than the
  existing 320-acre spacing.*  This unit is also  being evaluated
  for possible improved recovery projects  similar to those being
  studied at NEBU.

       Although now  largely  complete, development  of the  32-9
  Unit  began  later  and  has  proceeded  more slowly  than  the
  development  of NEBU.  Production from  the  32-9 Unit  did not
  commence until March of 1992.  Consequently, Devon believes the
  32-9 Unit has not yet reached its peak production rate.



<PAGE>

       Devon also  owns  an  interest in  five  wells  on  leases
  located  immediately adjacent  to the  32-9  Unit. These  wells
  will  not  be  committed  to the  32-9  Unit.  Unless otherwise
  indicated,  all references herein to the 32-9 Unit include both
  the 33 wells expected  to be included in the Unit  and the five
  wells outside  the Unit.  Devon does  not own  any interest  or
  reserves  in the deeper,  conventional sandstone  reservoirs at
  the 32-9 Unit.

       San Juan Basin  Gas Price.   The sales  price for  Devon's
  San Juan Basin  coal seam gas  production is  a combination  of
  the net wellhead  price, plus  additional revenue  attributable
  to the  San Juan Basin  Transaction.  The  average net wellhead
  price for San  Juan Basin coal seam production sold during 1995
  (before  the benefit  of the  San Juan  Basin Transaction)  was
  $0.71 per Mcf. This net realization is  relatively low compared
  to conventional  gas produced in other areas of  the U.S.  This
  occurred for two reasons:

         First, during  most of 1995,  demand for natural gas  in
  California (the  primary  market for  San Juan  Basin gas)  was
  weak,  causing San Juan Basin gas to  sell at a larger discount
  than gas that could be delivered to  higher demand areas of the
  U.S.   *Devon believes that  this supply/demand imbalance  will
  persist  throughout  1996,  but  should   dissipate  in  future
  years.*  

       Second, the price  for coal seam gas  production was  less
  than that  for Devon's conventional  gas in the  San Juan Basin
  because (i)  a  relatively large  portion  (about 10%)  of  the
  produced gas is  carbon dioxide which  is removed,  (ii) a  fee
  must be paid  to remove carbon  dioxide and  transport the  gas
  from the  field to  transmission lines  that carry  the gas  to
  market and (iii) a portion of the produced gas is used to  fuel
  compressors and other  field equipment.   This  is a  permanent
  circumstance that  will always affect  the price  of coal  seam
  gas production from the San Juan Basin.

       Offsetting the  deductions from the  wellhead price is  an
  additional $0.61 per  Mcf from the San  Juan Basin Transaction.
  This increase, added  to the net  wellhead price  of $0.71  per
  Mcf, resulted in  a San Juan Basin coalseam  gas price of $1.32
  per Mcf in 1995.  See " - San Juan Basin Transaction" below.

       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  be $0.61
  per  Mcf higher  than  the price  the  Company would  otherwise
  receive from 1995 through the year 2002.*  

       The transaction is  based on  the fact  that Devon's  coal
  seam  gas  production  qualifies  as  a  "nonconventional  fuel
  source"    under   Internal    Revenue   Service   regulations.
  Consequently,  gas produced from  these properties  through the
  year 2002  is eligible  for the  Section 29  Credit, which  was
  equal to $1.01  per million Btu  ("MMBtu") as  of December  31,

<PAGE>

  1995.    The  transaction  consists  of  four  major  elements.
  First, Devon  conveyed about 179  Bcf, or 90%,  of its year-end
  1994 coal  seam gas  reserves to the  unrelated party. However,
  for financial  reporting purposes Devon  retained all of  these
  reserves and  their future production and  cash flow  through a
  volumetric production  payment and 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.   (However, Devon has an option to reacquire
  these  reserves at  their  fair market  value  at the  time the
  option is  exercised.)   Third, the unrelated  party pays Devon
  an amount  equal to  75% of  the value  of the  Section 29  tax
  credits generated by  the properties.  Fourth, Devon retained a
  75%  reversionary interest  in any  reserves in  excess of  the
  186.2  Bcf   estimated  to  exist   as  of  the   date  of  the
  transaction.  The  transaction is  described in more  detail in
  note 3  to Devon's  consolidated financial statements  included
  elsewhere herein. 

       Permian  Basin  Properties.    The  Permian  Basin  covers
  approximately  66,000  square   miles  of  western  Texas   and
  southeastern  New Mexico.  The  area has  more  than 500  major
  fields  which are  grouped  under  the general  designation  of
  Permian  Basin.  Permian  Basin acreage  is  largely  "held  by
  production"  from existing  wells,  meaning that  new leasehold
  positions are  not readily  attainable. Since  1987, Devon  has
  made four  separate acquisitions of  properties in the  Permian
  Basin.   These   acquisitions,  especially   the   July,   1992
  acquisition of certain  Permian Basin properties, enabled Devon
  to  obtain prospective  acreage  in  areas in  which  leasehold
  positions   could    not   otherwise    be   purchased.    *The
  multi-objective  nature (several potential  producing zones) of
  the Permian  Basin and Devon's  large leasehold position  there
  will   continue  to   provide   Devon   with  exploration   and
  development  opportunities. Enhanced oil  recovery projects are
  also possible which could further expand Devon's reserves.*  

       Grayburg-Jackson Field.   This  field, which was  acquired
  in the Alta Merger in May, 1994, is located in Eddy County,  in
  the far southeastern New Mexico  portion of the Permian  Basin.
  It  is the  Company's single  largest property  in the  Permian
  Basin, accounting for 23% of  total oil and gas reserves.   Its
  location within 35  miles of 26 other Devon properties makes it
  an  ideal  strategic  fit  for   the  Company's  Permian  Basin
  holdings.

       Production  from  this  field  currently  comes  from  the
  Grayburg-San Andres-Premier zones  over a 400-foot  interval to
  depths up  to 4,000 feet. Although some of  the oldest wells in
  the  Field date  back to  the 1940's  and 1950's,  most of  the
  currently producing  wells were  drilled in  the early  1970's.
  Additional drilling over the years by previous owners left  the
  field developed to  an average of 40-acre spacing per well when
  Devon  acquired   it.  However,   similar  properties  in   the
  immediate vicinity  have been  drilled on  20-acre spacing  and
  successfully  waterflooded.   Based  upon this  information, in
  1994 Devon initiated a $60  million capital development project

<PAGE>

  which includes drilling about 150  wells over a two-  to three-
  year  period,  converting producing  wells  to  water injection
  wells and instituting a waterflood.   As of year-end  1995, the
  project was about 50% completed.

       From May  through year-end  1994, the  first seven  months
  Devon owned  the field,  production  from the  Grayburg-Jackson
  Field was 234  MBoe. This was approximately 3% of Devon's total
  1994  production.  For 1995,  production increased  to 920 MBoe
  as additional drilling was  completed and Devon owned the field
  for the full year.   *For 1996  production is expected to again
  increase as  development continues.*   Currently  about 50%  of
  the Grayburg-Jackson  Field reserves are classified  as "proved
  developed."   The  remaining  reserves  are considered  "proved
  undeveloped."  

       Worland Property.   In December, 1995 Devon  completed the
  acquisition  of  properties  from  a   major  oil  company  for
  approximately  $50.3  million.    All  of  the  properties  are
  located on a  25,000-acre federal unit in Big Horn and Washakie
  Counties, Wyoming.  Of the $50.3 million purchase  price, $46.3
  million  was  allocated  to    38  producing  wells, 16  proved
  undeveloped locations  and  a  natural  gas  processing  plant.
  These acquired assets,  combined with the small  interest Devon
  previously owned, had  total estimated proved reserves  of 16.0
  MMBoe as of  year-end 1995.  The remaining $4  million purchase
  price  was allocated  to  undeveloped  leasehold on  the  unit,
  which  constitutes about  60%, or  15,500 acres,  of  the total
  acreage acquired.

       *In  1996 Devon expects to invest an additional $9 million
  to  begin  the   exploitation  of  this  property.     Projects
  scheduled  for   1996  include   drilling  development   wells,
  optimization  of   the  existing   gas  processing  plant   and
  gathering system,  additional stimulation of existing wells and
  drilling  wells  to  extend  the   productive  limits  of  this
  property.*  

       In early 1996 Devon increased its working interest  in the
  proved  property to  98%  through several  smaller acquisitions
  totaling $7  million.   These acquisitions  also increased  the
  Company's interest in the gas  processing plant and undeveloped
  leases to 100%. 

       The property  consists  of three  separate fields  located
  along a major  geologic structure.   It is  the single  largest
  gas producing  feature in  the Bighorn  Basin.  Seven  separate
  horizons produce  on the  structure:  the  First, Second, Third
  and  Fourth  Frontier  sandstones,  the  Muddy  sandstone,  the
  Phosphoria  dolomite  and the  Tensleep  sandstone, ranging  in
  depths from  7,450 to 10,500  feet.  The  first production from
  this  property  was from  the Phosphoria  oil reservoir  in the
  1940s.  Shallow  gas production  was established in  the 1960s.
  The  Tensleep,  immediately  below  the  Phosphoria  zone,  was
  developed in the 1970s.   The original owner dedicated  all gas
  production from the  property, which they believed to be only a
  minor  by-product of  the  oil  production, under  a  long-term
  contract for $0.30 or less per Mcf.  Because of  this contract,

<PAGE>

  full development  of the  gas reservoirs  was not  economically
  feasible  until the  price  was  renegotiated by  the  original
  owner in 1988.  

       Devon believes  the major  potential of  this property  is
  from the  application of  modern technology.   Three-D  seismic
  and  new  well  completion techniques  such  as  massive  acid-
  fracturing,  are  proving  successful in  other  parts  of  the
  Bighorn Basin  and throughout  the Rocky  Mountain region,  and
  may enhance reserves and  recoveries at the Worland Property as
  well.    In addition,  both  the  Tensleep and  Phosphoria  are
  possible candidate zones for horizontal drilling technology. 

  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 1,372  of its 4,024  wells.  As
  operator,  Devon  receives  reimbursement  of  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.

  Title to Properties

       Title to properties is subject  to (i) royalty, overriding
  royalty,  carried,  net  profits,  working  and  other  similar
  interests, (ii) contractual arrangements  customary in the  oil
  and gas industry,  (iii) liens for  current taxes  not yet  due
  and (iv) 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  production 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,  there  are no  material
  pending  legal proceedings  to  which Devon  is  a party  or of
  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, 1995.

                              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.

                                                        Average
                                                        Daily
                                      High     Low      Volume
   1994:
   Quarter Ended March 31, 1994       22-7/8   17-1/2  55,131
   Quarter Ended June 30, 1994        26-1/2   17-1/4  37,547
   Quarter Ended September 30, 1994   23-1/4   19-3/4  26,344
   Quarter Ended December 31, 1994    22-1/4   16      34,110
   1995:
   Quarter Ended March 31, 1995       21-3/8   16-3/4  41,268
   Quarter Ended June 30, 1995        23-1/4   20      41,437
   Quarter Ended September 30, 1995   23-7/8   18      39,462
   Quarter Ended December 31, 1995    26       21-1/2  22,333
   1996:
   Quarter Ended March 31, 1996       25-3/4   21-1/4  45,322
   (through February 28, 1996)

   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. *Devon anticipates continuing to pay regular quarterly  dividends in
   the foreseeable future.*

         On February 27,  1996, there  were approximately  1,200 Devon  Common
   Stock shareholders of record.

<PAGE>

  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,
                                                  1995      1994      1993       1992     1991
                                                    (Thousands, Except Per Share Data)

   OPERATING RESULTS

      <S>                                      <C>         <C>       <C>       <C>       <C>
      Oil sales                                $ 55,290    38,086    38,395    27,329    9,436
      Gas sales                                  50,732    56,372    54,876    39,973   19,091
      NGL sales                                   6,404     4,908     4,544     1,370       --
      Other revenue                                 877     1,407       942     2,892    1,815

      Total revenues                           $113,303   100,773    98,757    71,564   30,342

      Lease operating expenses                 $ 27,289    24,521    26,401    18,430    8,689
      Gross production taxes                   $  6,832     6,899     6,924     4,600    1,912
      Depreciation, depletion and amortization $ 38,090    34,132    28,409    19,894    7,844
      General and administrative expenses      $  8,419     8,425     7,640     6,510    5,832
      Interest expense                         $  7,051     5,439     3,422     2,644    2,209
      Reduction of carrying value of oil and
              gas properties                   $     --        --        --        --   25,000

<F1>
      Net earnings (loss)                      $ 14,502    13,745    20,486 1  14,615  (15,024)

      Net earnings (loss) per share:
<F1>
              Assuming no dilution             $   0.66      0.64      0.98 1    0.94    (1.99)
<F1>
              Assuming full dilution           $   0.66      0.64      0.98 1    0.90    (1.99)

      Cash dividends:
              Per preferred share              $     --        --        --      1.46     1.94
              Per common share                 $   0.12      0.12      0.09        --       --

      Weighted average common shares
        outstanding                              22,074    21,552    20,822    13,802    8,687

   BALANCE SHEET DATA

      Total assets                             $421,564   351,448   285,553   225,972  102,107
      Long-term debt                           $143,000    98,000    80,000    54,450   32,000
      Stockholders' equity                     $219,041   206,406   172,900   153,267   53,015 

   PRODUCTION/PRICE DATA

      Production:
              Oil (MBbls)                         3,300     2,467     2,337     1,446      484
              Gas (MMcf)                         36,886    39,335    35,598    28,374   15,398
              NGLs (MBoe)                           600       501       411       112       --
<F2>
              MBoe  2                            10,047     9,524     8,681     6,287    3,050

      Average prices:
              Oil (Per Bbl)                    $  16.75     15.44     16.43     18.89    19.49
              Gas (Per Mcf)                    $   1.38      1.43      1.54      1.41     1.24
              NGLs (Per Boe)                   $  10.68      9.79     11.06     12.28       --
<F2>
              Per Boe  2                       $  11.19     10.43     11.27     10.92     9.35

<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  Gas and NGLs are converted to Boe or  MBoe at the rate of six Mcf of gas
      per barrel of oil  and 42 gallons of NGLs per barrel  of oil, based upon
      the  approximate relative energy content  of natural gas,  oil and NGLs,
      which rate is not necessarily indicative of the relationship of oil, gas
      and NGL 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  1993 through 1995. Reference  is made
  to  "Item 6.  Selected Financial  Data" and "Item  8. Financial
  Statements  and Supplementary Data."

  Overview

     Many of the  major trends  for Devon have  been positive  in
  recent history.  During the last three years:

          the company's major assets,  oil and gas reserves, have
          grown  87% to  115  million barrels  of oil  equivalent
          ("MMBoe"),

          annual oil and  gas production has risen 60% (from that
          of 1992) to 10 MMBoe,

          total revenues  for 1995 were 58% higher  than those of
          1992, and

          cash margins  (total revenues less cash  expenses) have
          expanded to the $50 million to $60 million range.

     However,  non-cash  expenses, such  as  higher depreciation,
  depletion and  amortization and  volatile oil  and gas  prices,
  have  produced  more  variable results  in  net earnings.   Net
  earnings were down in  1994 compared to  1993, but up in  1995.
  Even  so,  the net  earnings  of  $14.5  million (1995),  $13.7
  million (1994), $19.2  million (1993) and $14.6 million  (1992)
  were all substantially above the previous best year  in Devon's
  history of $4.4 million in 1981.

     Devon's  liquidity and  financial condition  also  have been
  strong  during the  last  three  years compared  to  historical
  levels.   After the February 1996  annual review  by its banks,
  Devon's credit  lines have  increased 117%  since 1992  to $260
  million.   Of this, $110  million was unused as  of the end  of
  February 1996.   Net cash provided by operating  activities has
  been  $61.3 million,  $46.4 million and  $64.0 million the last
  three years,  compared to  an average  of $14  million for  the
  years 1988 through 1992.

     Devon has taken  several actions in recent  years to achieve
  its growth in operations and financial condition:

          Devon  acquired  a   substantial  suite  of  properties
          primarily located  in the Permian Basin  in July, 1992.
          This  $130  million   acquisition  caused   significant
          improvement  in  both oil  and  gas  production and  in
          revenues from the second half of 1992 onward.

          Devon acquired $54 million  of coal seam gas properties
          in  the San Juan Basin in June, 1993.  These properties
          added  to  Devon's  already significant  coal  seam gas
          properties and production in the San Juan Basin. <PAGE>
 

          Devon   acquired  the   properties   of   Alta   Energy
          Corporation through a $72  million merger in May, 1994.
          The oil and gas  properties acquired through the merger
          (the  "Merger Properties")  have added  substantial oil
          and gas  reserves, production and  revenues to  Devon's
          Permian Basin position.

          Devon  acquired  certain Wyoming  oil  and  natural gas
          properties  and a  gas processing  plant  (the "Worland
          Properties") for approximately $50 million in December,
          1995.

          In  1995, Devon  entered  into  a transaction  covering
          substantially all of its  San Juan Basin coal seam  gas
          properties  (the  "San Juan  Basin  Transaction").   In
          1995,  this transaction  boosted  Devon's  revenues  by
          $11.4 million.  This transaction also added $44 million
          to Devon's pre-tax discounted present value of year-end
          oil and gas reserves.

          Devon has  been successful during the  last three years
          in its  drilling efforts.  Devon has  spent almost $125
          million to drill 384 wells, of which 368 were completed
          as producers.  Most of these efforts have been centered
          around the 1992 Permian  Basin acquisition and the 1994
          Merger.    These  properties,  along  with  the Worland
          Properties,  are expected  to account  for some  60% of
          Devon's 1996  drilling and  development  budget of  $70
          million to $80 million.

          Devon's  acquisition  and drilling  efforts  during the
          last  three  years  have  added 74.5  MMBoe  of  proved
          reserves to its  asset base.  Combined  with 13.7 MMBoe
          of upward  revisions to its reserve  estimates, Devon's
          total reserve  additions of 88.2 MMBoe  during the past
          three years were 312% of its production of 28.3 MMBoe.

          Devon has sought to control its well operating expenses
          in  part   by   selling  marginal   and   non-strategic
          properties.  Though the  absolute dollar amount of well
          operating expenses  increased by almost 50%  since 1992
          as  Devon  expanded  its  production   and  operations,
          Devon's sales of  approximately 2,900 wells during  the
          period  helped  to  lower  the  expenses  per  unit  of
          production  by 7%.   The  combination of  expanding its
          significant properties  and selling the minor  ones has
          increased  Devon's  economies   of  scale  and  overall
          efficiency.

          Devon's  reserve  additions over  the past  three years
          have also  increased capital resources via increases in
          Devon's  lines of credit.   Since the end  of 1992, and
          including  the   banks'  annual  review   completed  in
          February, 1996, Devon's credit lines have increased  by
          $140 million to a total of $260 million.  Though total
          debt has  increased,  the  unused  portion  of  Devon's
          credit lines has increased some $50 million.


  Results of Operations

     Changes in oil, gas and NGL production,  prices and revenues
  from 1993 to 1995 are shown in the table below.
<TABLE>
<CAPTION>
                                                       Ended December 31,
                                                      1995             1994                                  
                                              1995   vs 1994    1994  vs 1993  1993
    Production
     <S>                                      <C>       <C>     <C>     <C>   <C>
     Oil (MBbls)     . . . . . . . . . . . .  3,300     +34%    2,467   +6%   2,337
     Gas (MMcf)      . . . . . . . . . . . . 36,886      -6%   39,335  +10%  35,598
     NGLs (MBoe)     . . . . . . . . . . . .    600     +20%      501  +22%     411
     Oil, Gas and NGLs (MBoe)  . . . . . . . 10,047      +5%    9,524  +10%   8,681

   Revenues
     Per Unit of Production:
       Oil (per Bbl) . . . . . . . . . . . .$ 16.75      +8%    15.44   -6%   16.43
       Gas (per Mcf) . . . . . . . . . . . .$  1.38      -3%     1.43   -7%    1.54
       NGLs (per Boe)  . . . . . . . . . . .$ 10.68      +9%     9.79  -11%   11.06
       Oil, Gas and NGLs (per Boe) . . . . .$ 11.19      +7%    10.43   -7%   11.27

   Absolute                                                                   
                                                             (Thousands)
       Oil . . . . . . . . . . . . . . . . $ 55,290     +45%   38,086   -1%  38,395
       Gas . . . . . . . . . . . . . . . . $ 50,732     -10%   56,372   +3%  54,876
       NGLs  . . . . . . . . . . . . . . . $  6,404     +30%    4,908   +8%   4,544
       Oil, Gas and NGLs . . . . . . . . . $112,426     +13%   99,366   +2%  97,815

</TABLE>
         Oil Revenues  1995 vs. 1994  Oil revenues rose $17.2 million in 1995.
   Substantial  gains in production  added $12.9 million to  revenues in 1995,
   while higher average prices added the remaining $4.3 million.

         The  Merger  Properties  produced 843,000  barrels  in  1995, a  239%
   increase from  the  249,000  barrels  which were  produced  during  Devon's
   ownership for the last seven months of 1994.  Production from Devon's other
   oil  properties increased 11%  in 1995, from  2,218,000 barrels  in 1994 to
   2,457,000 barrels in 1995.

         1994 vs. 1993   Oil revenues were essentially  unchanged from 1993 to
   1994.   A  130,000 barrel  boost in  production added  $2.1 million  to oil
   revenues.  Unfortunately, a decrease in oil prices subtracted $2.4 million.

         The Merger Properties added  249,000 barrels of additional production
   during  the last  seven  months  of 1994,  while Devon's  other  properties
   accounted for a net  decrease of approximately 119,000 barrels  in 1994 due
   to  the  effect  of property  sales in  1993.   Devon  sold  various minor,
   marginally profitable  or non-strategic properties throughout  1993.  These
   properties produced approximately 173,000 barrels of oil in 1993.


         Gas Revenues  1995 vs. 1994  Gas revenues  decreased $5.6 million, or
   10%, in 1995,  due to a combination of lower  production and prices.  Lower
   production  accounted for $3.5 million of the revenue decrease, while lower
   gas prices accounted for the remaining $2.1 million.

         Gas revenues  in 1995 were  down despite the  positive effect of  the
   1995  San  Juan Basin  Transaction.   Such  transaction boosted  1995's gas
   revenues by $11.4 million, and raised the average prices for 1995 coal seam
   gas and total gas production by $0.61 and $0.35 per Mcf, respectively.  See
   Note  3 to the consolidated financial statements included elsewhere in this
   Form 10-K for a detailed discussion of the San Juan Basin Transaction.

         Coal seam  gas production declined by  5%, from 22.0  Bcf in 1994  to
   20.8 Bcf in 1995.   This decline of 1.2 Bcf was  due to the San Juan  Basin
   Transaction which, among other things, included the sale of a small portion
   of Devon's coal seam gas properties.

         The  average realized coal seam gas price rose by 13%, from $1.17 per
   Mcf in 1994 to $1.32 per Mcf  in 1995.  The $0.61 per Mcf increase from the
   San Juan Basin  Transaction more than offset a $0.46  per Mcf price drop at
   the wellhead.   Total coal  seam gas  revenues were $27.5  million in  1995
   versus  $25.7 million  in 1994.   Coal seam  gas revenues  in 1995 included
   $14.7  million of wellhead sales and $12.8 million of revenues attributable
   to the  San  Juan Basin  Transaction.   The sale  of the  small portion  of
   Devon's  coal seam  gas properties  which was  part of  the San  Juan Basin
   Transaction  had the effect  of reducing 1995's  coal seam  gas revenues by
   $1.4  million  as  compared  to  1994's revenues.    The  $12.8  million of
   additional  gas sales received pursuant to the  terms of the San Juan Basin
   Transaction, less the $1.4 million  of wellhead sales reduction as a result
   of  the small sale,  nets to  the $11.4 million  increase in coal  seam gas
   sales  from  the San  Juan  Basin Transaction  referred  to  in the  second
   paragraph above.

         Total conventional gas production and revenues for 1995 were 16.1 Bcf
   and $23.2 million, respectively, versus 17.4 Bcf and $30.7 million in 1994.
   Prices for  conventional gas averaged  $1.44 per  Mcf in  1995 compared  to
   1994's average of $1.76 per Mcf.

         Production for a  full year from the Merger Properties  contributed a
   0.6 Bcf  increase in gas production  in 1995.   However, this increase  and
   others from wells drilled in 1994 and 1995 were more than offset by reduced
   production  from other  conventional gas  wells.   The primary  areas where
   conventional production  declined in 1995  were the Ozona  field and  NEBU.
   High pipeline pressure  and down time for repairs contributed  to a 0.6 Bcf
   reduction in  Ozona production in  1995.   Although Devon does  not have  a
   significant  interest in conventional  gas production in NEBU,  it has been
   receiving  more than its  normal share of production  through gas balancing
   and also  received nonrecurring  payments for inventory  gas in  1994.   In
   1995,  the amounts of  imbalance makeup and inventory  sales declined, thus
   leading to a  0.5 Bcf reduction in conventional NEBU production compared to
   1994.  Also, various marginal wells sold during 1994 and 1995 accounted for
   a 0.6 Bcf reduction in conventional production in 1995.

         1994 vs. 1993  Gas  revenues increased $1.5 million, or 3%,  in 1994,
   as a 7% drop in prices dampened the effect of a 10% increase in production.
   Gas production increases  boosted gas revenues by $5.8  million.  Lower gas
   prices reduced gas revenues by $4.3 million. 

         Approximately  2.2 Bcf of the production increase was attributable to
   coal seam  gas production from  NEBU and  the 32-9 Unit  Properties.   NEBU 
   production increased from 18.2 Bcf in 1993 to 18.7 Bcf in 1994.  Production
   from the 32-9 Unit  Properties increased from 1.6 Bcf in 1993 to 3.3 Bcf in
   1994 due to  the fact that such  properties were acquired  by Devon in  the
   middle of 1993, and therefore contributed only six months of  production to
   Devon's 1993 totals.

         Total coal  seam gas production and  revenues for 1994  were 21.9 Bcf
   and  $25.7 million,  respectively, versus  19.8 Bcf  and $27.7  million for
   1993.   Prices for  coal seam gas  averaged $1.17 for 1994  versus $1.40 in
   1993.    The  price  per  Mcf  for  coal  seam  gas is  less  than  Devon's
   conventional  gas (i.e.,  gas  produced from  other  than  coal formations)
   primarily  due  to   the  former's  low  Btu  content   and  the  costs  of
   transportation and  removing carbon dioxide.   These adjustments have  been
   taken into account in calculating the coal seam sales prices referred to in
   this discussion.  Beginning in 1995, as discussed above, the San Juan Basin
   Transaction increased the coal seam price to a level much closer to Devon's
   conventional gas prices.

         Total conventional gas production and revenues for 1994 were 17.4 Bcf
   and $30.7 million, respectively, versus 15.8 Bcf and $29.2 million in 1993.
   Prices  for conventional gas  averaged $1.76 per Mcf  compared to $1.84 per
   Mcf in 1993.

         Approximately 0.6 Bcf of conventional gas production was added during
   1994 from the Merger Properties.  Also, approximately 1.5 Bcf of additional
   1994 production was  contributed by the Ozona field and  related properties
   in  the Permian Basin.  The Ozona properties were part of the Permian Basin
   Properties  acquired in  July  1992.   However,  prior to  September  1993,
   substantially all  of the  gas produced  from such  properties was  used to
   satisfy  a  recoupment  obligation  created  by  the  prior  owner  of  the
   properties.   Therefore,  Devon only began  recognizing production  and gas
   revenues  from  these  properties  in September  1993.    More importantly,
   production  from  the Ozona  properties  more than  doubled due  to Devon's
   drilling efforts in this field.

         Approximately 0.9  Bcf of gas  was produced in  1993 from  properties
   which  were sold during  1993.  Therefore, these  properties contributed no
   production  in 1994.  Also, gas production  declined 0.2 Bcf in 1994 due to
   properties which were sold in 1994 and therefore did not produce for a full
   year as they did in 1993.

         NGL Revenues  1995 vs.  1994  NGL revenues increased by  $1.5 million
   in 1995.  Higher production contributed $1.0 million of the increase, while
   the remaining $0.5 of increased revenues was attributable to higher average
   prices in 1995.

         The  Merger Properties  accounted  for 52,000  Boe  of  the increased
   production.    Such properties  produced  84,000 Boe  in 1995,  compared to
   32,000 Boe during the seven months Devon owned the properties in 1994.  

         1994  vs. 1993    A  90,000 Boe  increase  in  NGL production  raised
   revenues by $1.0 million.  A decrease in prices subtracted $0.6 million.

         Approximately 32,000 Boe of production was added during 1994 from the
   Merger Properties.   The remaining  increase was primarily attributable  to
   Devon's drilling efforts in 1993 and 1994.

         Expenses  The details of the changes in pre-tax expenses between 1993
   and 1995 are shown in the table below.
<TABLE>
<CAPTION>
                                                        Year Ended December 31,
                                                        1995              1994
                                                1995   vs 1994    1994   vs 1993  1993
                                                     (Absolute Amounts in Thousands)
<F1>
    Absolute(1):
     Production and operating expenses:
       <S>                                    <C>        <C>     <C>       <C>   <C>
       Lease operating expenses  . . . . . .  $27,289    +11%    24,521    -7%   26,401
       Production taxes  . . . . . . . . . .    6,832     -1%     6,899     -     6,924
     Depreciation, depletion and amortization
        attributable to:
       Oil and gas production  . . . . . . .   36,640    +11%    32,861   +20%   27,420
       Non-oil and gas properties  . . . . .    1,450    +14%     1,271   +29%      989
     General and administrative expenses . .    8,419      -      8,425   +10%    7,640
     Interest expense  . . . . . . . . . . .    7,051    +30%     5,439   +59%    3,422

         Total       . . . . . . . . . . . .  $87,681    +10%    79,416    +9%   72,796

<F1>
   Per Boe(1):
     Production and operations expenses:
       Lease operating expenses  . . . . . .   $ 2.72     +6%      2.57   -15%     3.04
       Production taxes  . . . . . . . . . .     0.68     -7%      0.73    -9%     0.80
     Depreciation, depletion and amortization
      attributable to:
       Oil and gas production  . . . . . . .     3.65     +6%      3.45    +9%     3.16
       Non-oil and gas properties  . . . . .     0.14     +8%      0.13   +18%     0.11
     General and administrative expenses . .     0.84     -6%      0.89    +1%     0.88
     Interest expense  . . . . . . . . . . .     0.70    +23%      0.57   +43%     0.40

        Total        . . . . . . . . . . . .   $ 8.73     +5%      8.34    -1%     8.39

<F1>
   (1)      Though  per unit  general  and  administrative expenses,  interest
            expense and non-oil  and gas property depreciation  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 1993 and  1995 are shown  in the
   table below.

<TABLE>
<CAPTION>

                                                        Year Ended December 31,
                                                        1995              1994
                                               1995    vs 1994    1994   vs 1993    1993
                                                    (Absolute Amounts in Thousands)
    Absolute:
     <S>                                      <C>        <C>     <C>       <C>    <C>
     Recurring lease operating expenses  . .  $23,842    +10%    21,583    -3%    22,317
     Well workover expenses  . . . . . . . .    3,447    +17%     2,938   -28%     4,084
     Production taxes  . . . . . . . . . . .    6,832     -1%     6,899     -      6,924
        Total production and operating
          expenses                            $34,121     +9%    31,420    -6%    33,325

   Per Boe:
     Recurring lease operating expenses  . .   $ 2.37     +4%      2.27   -12%      2.57
     Well workover expenses  . . . . . . . .     0.35    +17%      0.30   -36%      0.47
     Production taxes  . . . . . . . . . . .     0.68     -7%      0.73    -9%      0.80
        Total production and operating
          expenses                             $ 3.40     +3%      3.30    -14%     3.84

</TABLE>
      1995  vs. 1994   Recurring  lease operating  expenses increased  by $2.2
   million,  or 10%, in 1995.  Approximately  $1.6 million of the increase was
   related to the  Merger Properties, whose costs increased from  $1.9 million
   in 1994 (for the last seven months of the year during which they were owned
   by  Devon)  to $3.5  million  in 1995.    However, on  a  cost per  unit of
   production basis, the Merger Properties' recurring lease operating expenses
   dropped from  $4.96 per Boe  in 1994 to $3.16  per Boe in 1995.   These per
   unit costs  compare to the averages  for Devon's other  properties of $2.15
   per Boe in 1994 and $2.28 per Boe in 1995.

      1994  vs. 1993    Recurring lease  operating  expenses dropped  by  $0.7
   million, or  3%, in 1994.  The positive  effect from the sale of over 2,000
   wells in  1993 was partially offset  by additional expenses  related to the
   Merger  Properties.   The  Merger  Properties  are primarily  oil producing
   properties,  which are  traditionally more  expensive to  operate  than gas
   producing  properties.  For  the year 1994, the  Merger Properties incurred
   $1.9  million  of recurring  lease  operating expenses,  or $4.96  per Boe,
   compared to  $19.7 million  of such  costs, or $2.15  per Boe,  incurred on
   Devon's other properties.

      Workover expenses dropped by $1.1 million, or 28%, in 1994.  Most of the
   reduction occurred in certain Permian Basin properties acquired in 1992.  A
   substantial  number of workover projects  were completed on such properties
   in 1993 as  Devon became more familiar with  these properties following the
   acquisition.  The need for workovers on these properties declined in 1994.

      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.

      1995  vs. 1994   Oil  and gas  property related  DD&A increased  by $3.8
   million,  or 11%, in 1995.  Approximately $2.0 million of this increase was
   caused by an increase in the DD&A rate  from $3.45 per Boe in 1994 to $3.65
   per  Boe in  1995.   The increased  DD&A rate was  primarily caused  by the
   inclusion  of the Merger  Properties for  a full year in  1995, compared to
   only  seven months in 1994.  The remaining  $1.8 million of the increase in
   oil  and gas  property related  DD&A was  caused by  the increase  in total
   production in 1995.

      1994 vs. 1993  Oil and gas property related DD&A increased $5.4 million,
   or 20%,  in 1994.  Approximately  50% of this  increase was related  to the
   increase in combined oil, gas  and NGL production in 1994.  The  other half
   of the increased expense was due to an increase in the DD&A rate from $3.16
   per Boe in  1993 to  $3.45 per  Boe in 1994.   The addition  of the  Merger
   Properties in 1994 was  the primary cause for the increased DD&A rate.  The
   DD&A  rate  for  the seven  months  following the  addition  of  the Merger
   Properties was $3.60 per Boe.

      General and  Administrative Expenses  ("G&A")   1995 vs.  1994   G&A was
   constant between  1995 and 1994.   Employee salaries  and related  overhead
   burdens increased by $0.3 million, legal fees increased by $0.3 million and
   abandoned acquisition  costs rose by  $0.1 million.   These increases  were
   offset by a $0.6 million increase in G&A reimbursements received from joint
   interest owners in Devon-operated  properties and a $0.1  million reduction
   in franchise taxes.   Approximately  $0.2 million  of the  increase in  G&A
   reimbursements related  to a change  in the  method used  to calculate  the
   reimbursements on certain  properties, and  such change was retroactive  to
   the prior  two  years.   The  reduction in  franchise taxes  resulted  from
   Devon's reincorporation from Delaware to Oklahoma in June 1995.

      1994  vs. 1993   G&A increased  approximately $0.8  million, or  10%, in
   1994.   Employee  salaries  and  related overhead  burdens such  as  health
   insurance, payroll taxes and pension expenses rose by $1.4 million, or 16%.
   These  increases were  partially  offset  by a  $0.3 million  reduction  in
   abandoned  acquisition costs  and  a  $0.3  million  increase  in  overhead
   reimbursements  received  from  joint  interest  owners  in  Devon-operated
   properties.

      Interest Expense   1995  vs. 1994   Interest expense  increased by  $1.6
   million, or  30%, in  1995.   This increase was  due almost  exclusively to
   higher rates  in 1995,  which accounted for  $1.3 million of  the increased
   interest expense.  The  interest rate on the  debt outstanding during  1995
   was  6.5%, compared  to 1994's  rate of  5.2%.   The overall  interest rate
   (including  the  effect  of  various  fees  paid  to  the  banks  and   the
   amortization of  certain loan costs) averaged 7.3% in 1995, compared to the
   1994 overall rate of 5.9%.  

      The  remaining $0.3  million of  interest expense  increase in  1995 was
   caused by  a higher average balance outstanding.   The average debt balance
   during  1995 was $97.1 million, compared to 1994's average balance of $92.5
   million.

      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 principal amount  of the swap agreement is $75  million, and the
   other party to the agreement is one of the lenders of Devon's credit  lines
   (the "Lender").   The  agreement terminates  on June  16, 1998,  unless the
   Lender exercises its right to extend the termination date to June 16, 2000.
   The terms of the agreement provide for quarterly payments either to or from
   Devon,  determined by whether the three month London Interbank Offered Rate
   ("LIBOR") in effect  at the beginning of each quarterly  calculation period
   is greater  or  less than  5.6%.    The calculation  periods begin  on  the
   sixteenth day of each  March, June, September and December  during the term
   of the  agreement.   If,  on the  date of  the beginning  of the  quarterly
   calculation period, the three month LIBOR exceeds 5.6%, the Lender will owe
   Devon the  quarterly amount of the  excess rate applied to  the $75 million
   principal.    Alternately,  if  the three  month  LIBOR  on the  applicable
   quarterly date is less than 5.6%, Devon will owe the Lender.

      The swap agreement is accounted for as a hedge, with the amount which is
   either due to or from Devon recorded as a reduction or increase in interest
   expense.  The three month  LIBOR exceeded 5.6% at the beginning of  each of
   the  three  quarterly  calculation  periods  in  1995.    Therefore,  Devon
   recognized $0.1 million as a reduction to interest expense in 1995.

      The swap agreement  does not alter or affect any  terms or conditions of
   Devon's credit lines.

      1994 vs. 1993  Interest expense increased $2.0 million, or 59%, in 1994.
   The  average long-term  debt balance  outstanding rose  from $66.6  million
   during 1993 to $92.5 million  during 1994.  The  borrowings used to fund  a
   portion of the cash used in the Merger, along with the effect of  borrowing
   $50.0  million  at  mid-year  1993 to  acquire  the  32-9 Unit  Properties,
   accounted for the increased average debt during 1994.  The interest rate on
   the debt outstanding  increased from  4.2% in 1993  to 5.2% in  1994.   The
   overall interest rate rose from 5.1% in 1993 to 5.9% in 1994.

      Income Taxes    1995 vs 1994   Devon's effective  financial tax rate  in
   1995 was 43%, compared to the statutory federal rate  of 35%.  State income
   taxes and  certain tax aspects of  the San Juan Basin  Transaction were the
   primary factors which increased Devon's  financial tax rate.  The  San Juan
   Basin Transaction  also had a significant  effect on the portion  of income
   taxes which are current versus deferred.

      1994 vs.  1993  Devon's  effective financial  tax rate in  1994 was  36%
   compared to the  statutory federal  rate of 35%.   The effective  financial
   rate rose above  the federal statutory rate primarily due  to the effect of
   state income taxes.

   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 $117.6 million of cash was spent in
   1995 for capital expenditures, of which  $114.9 million was related to  the
   acquisition, drilling or  development of oil and gas properties.   Included
   in  this total is  $50.4 million  spent in December to  acquire the Worland
   Properties,  including  $0.1  million  of  third  party  costs  which  were
   capitalized  as  part  of  the  transaction.    Most  of the  drilling  and
   development efforts in  1995 centered in the Permian Basin,  which included
   183  of the 199  wells which  Devon drilled during  1995.  Included  in the
   Permian  Basin  activity was  approximately  $30.1  million  spent  in  the
   Grayburg-Jackson Field acquired in the May 1994 Merger.  Devon completed 88
   infill wells in the Grayburg-Jackson  Field, and an additional 9 such wells
   were  in various  stages of  drilling or  completion as  of  year-end 1995.
   Devon  also began the initial stages of a waterflood program on this field.
   *Drilling of an additional 40 infill wells is expected  to commence in 1996,
   along with the completion of the waterflood program.*

      Other Cash Uses  A $0.03 per common share dividend has been paid in each
   quarter  since Devon paid its  initial common stock dividend  in the second
   quarter of 1993.   This quarterly rate translates to  a cash demand of $2.7
   million  annually.   *Management expects  the policy  of paying  a quarterly
   dividend to continue.*

      Capital  Resources  and  Liquidity    Net  cash  provided  by  operating
   activities  ("operating cash flow")  was the primary source  of capital and
   short-term  liquidity in 1995.   Operating cash flow  in 1995 totaled $61.3
   million,  a 32% increase  compared to the  $46.4 million of  operating cash
   flow generated in 1994.

      In addition  to operating cash  flow, Devon's credit lines  have been an
   important source of capital and liquidity.  At year-end 1995,  these credit
   lines  totaled $205  million.   Devon's December  31, 1995  borrowings from
   these  credit  lines  were  $143 million,  leaving  $62  million of  credit
   available  for future  use.   In 1996,  the banks  revised the  credit line
   upward from $205  million to $260 million.  (See Note 7 to the consolidated
   financial  statements  included  elsewhere in  this report  for  a detailed
   discussion of the credit lines.)

      Devon's   San  Juan  Basin  coal  seam  gas  production  is  subject  to
   uncertainties  regarding   additional  royalties   and  taxes.     If  such
   uncertainties are resolved in 1996,  they are likely to require the  use of
   operating  cash flow, but Devon does not  expect such amount to be material
   to  its overall  liquidity,  capital  resources or  net  earnings.   For  a
   complete  discussion  of these  matters,  see Note  11 to  the consolidated
   financial statements contained elsewhere in this report.

   1996 Estimates

      The forward-looking statements provided in this discussion are  based on
   management's examination  of historical operating trends,  the December 31,
   1995 reserve  report of  LaRoche,  data in  Devon's  files and  other  data
   available from third parties.  The forward-looking statements were prepared
   assuming demand,  curtailment, producibility and  general market conditions
   for Devon's  oil,  natural gas  and  NGLs for  1996 will  be  substantially
   similar to those of 1995,  unless otherwise noted.  Devon cautions that its
   future oil and gas  production and expenses are subject to all of the risks
   and uncertainties normally incident to  the exploration for and development
   and production  of oil and gas.   These risks include, but  are not limited
   to, environmental  risks, drilling  risks and the  uncertainty inherent  in
   estimating future oil and gas production or reserves.

      Given the limitations expressed in the above paragraph, Devon's forward-
   looking statements for 1996 are set forth below.

      Oil Revenues   Devon expects its oil production in 1996 to total between
   3.7 million  barrels and 4.3 million  barrels.  Devon  expects its net  oil
   prices will average  from between  $0.10 below  to $0.10  above West  Texas
   Intermediate posted prices in 1996.

      Gas Revenues   Devon expects  its total gas  production in 1996  will be
   between  34.6 and 40.3 Bcf.   It is expected that  coal seam gas production
   will  be 17.1 Bcf to 19.9 Bcf  in 1996.  Devon  expects production from its
   conventional gas properties to total between 17.5 Bcf and 20.4 Bcf in 1996.
   Included  in the 1996 conventional gas production  estimates are 3.1 Bcf to
   3.6  Bcf of  estimated production  from the  Worland Properties  which were
   acquired in mid-December 1995.

      The incremental $0.61 per Mcf added to  coal seam gas prices by the  San
   Juan  Basin Transaction should offset a substantial portion of the negative
   price  effect from the  low BTU content  and the  transportation and carbon
   dioxide removal costs previously  discussed.  Therefore, Devon  expects its
   1996 coal  seam average  price will  be between $0.15  and $0.65  less than
   Texas Gulf  Coast spot averages.   Devon's conventional gas  is expected to
   average  $0.15 to  $0.25 per  Mcf less  than Texas  Gulf Coast  spot prices
   during 1996.   This conventional gas  price differential is larger  than in
   the last two years due to the inclusion of the  Worland Properties in 1996.
   Gas  production sold  from the  Worland Properties  is expected  to average
   $0.55 to $0.65 per Mcf less than Texas Gulf Coast spot prices during 1996.

      From December  of 1995 through  February of 1996,  the prices  for Texas
   Gulf Coast  and "Henry Hub" gas  have been radically higher  than those for
   virtually  all  other  major  basins  in the  U.S.    Therefore,  the basin
   differentials  quoted above  should be  regarded as  particularly volatile.
   The differentials  quoted above are  based more on  historical levels  than
   those of the last three or four months.

      NGL Revenues   Devon  expects its  production of NGLs  in 1996  to total
   between 800,000  Boe and  950,000  Boe.   Included in  these estimates  are
   240,000 Boe  to  280,000 Boe  estimated to  be produced  in  1996 from  the
   Worland Properties.

      Production  and  Operating   Expenses    The  addition  of  the  Worland
   Properties and the higher number of wells producing at the Grayburg-Jackson
   Field  should  be  the  primary contributors  to  an  expected increase  in
   recurring  lease  operating expenses  in  1996,  and the  resulting  higher
   revenues  should cause gross  production taxes  to also  rise.   Also, well
   workover expenses are anticipated to increase in 1996.  Future oil, gas and
   NGL prices have a direct effect on gross production taxes to be incurred in
   1996.  Future prices could also have an effect on whether proposed workover
   projects are economically feasible.  These factors contribute to the margin
   of  error inherent  in estimating  future  production and  operating costs.
   Given these uncertainties, Devon estimates that 1996's total production and
   operating  costs will be  between $39 million  and $45  million, or between
   $3.50 per Boe and $4.00 per Boe.

      Depreciation, Depletion and Amortization  The 1996 DD&A rate will depend
   on  numerous factors  which cannot  be reasonably  predicted at  this time.
   Most notable among  such factors are  the amount  of proved reserves  which
   will  be added from drilling efforts in 1996 compared to the costs incurred
   for  such efforts,  and  the  revisions to  Devon's year-end  1995  reserve
   estimates which  will be made during  1996.  Assuming a  1996 rate constant
   with  1995's rate  of $3.65  per Boe,  and the  estimated range  from  a 3%
   increase  to a 19% increase in total  oil, gas and NGL production discussed
   earlier  in  this section,  1996  DD&A expense  (including non-oil  and gas
   property related DD&A) is expected to increase to approximately $39 million
   to $45 million.

      General and Administrative Expenses  G&A is expected to  be between $8.8
   million and $9.4 million in 1996.

      Interest Expense  Future oil, gas and NGL prices and interest rates have
   a significant effect  on Devon's interest expense.   The interest rate swap
   entered into in 1995 removes the uncertainty  of future interest rates from
   a portion, but  not all of, Devon's  long-term debt.  Also, Devon  can only
   marginally influence the prices it will receive in 1996  from sales of oil,
   gas  and NGL.   These  factors  increase the  margin of  error  inherent in
   estimating future interest expense.   Other factors  which affect  interest
   expense, such as the amount and  timing of capital expenditures, are within
   Devon's control.  Given the uncertainty of future prices and interest rates
   and their ultimate  effect, Devon estimates that  it will incur between  $9
   million and $11 million of interest expense in 1996.

      Income Taxes  Devon expects its financial income tax  rate in 1996 to be
   between 41% and 46%.  Regardless of the level  of pre-tax earnings reported
   for  financial  purposes, approximately  $2  million  of Devon's  financial
   income tax expense is "fixed" due to various aspects of the 1994 Merger and
   the San  Juan Basin Transaction.   Therefore, if the actual  amount of 1996
   pre-tax  earnings differs materially from what Devon currently expects such
   amount to  be, the actual  financial income  tax rate for  1996 could  fall
   outside of the expected rate of 41% to 46%.  Also, based on Devon's current
   expectations  of 1996 taxable  income, which are largely  dependent on 1996
   oil and  gas prices, Devon  anticipates its current portion  of 1996 income
   taxes will be between $3 million and $5 million.

      Capital  Expenditures  Devon  expects its 1996  capital expenditures for
   drilling  and development efforts  will total between $70  and $80 million,
   including low  risk development  projects of approximately $21  million for
   the Grayburg-Jackson Field activities described above, and approximately $9
   million  on the Worland Properties.  Devon  also plans to spend another $20
   million to $25  million on  new, higher  risk/reward projects  in the  Gulf
   Coast and Permian Basin areas.  Devon  has not given effect to any possible
   success associated with this $20 million to $25 million in its oil  and gas
   reserve or production estimates.

      In addition to these 1996 capital estimates, Devon also expects to incur
   an additional  $6 million to  $9 million in  1997 on certain  of its proved
   undeveloped properties, with approximately half of such amount attributable
   to the Worland Properties.

      Though Devon has completed at least one major acquisition in each of the
   last several 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.

      The estimated future drilling and development activities are expected to
   be  funded  through a  combination  of  working  capital,  cash  flow  from
   operations and  borrowings from its  credit lines.   Devon considers  these
   capital resources, which  are discussed in  detail below,  to be more  than
   adequate to fund these anticipated costs.

      The   above  estimates   of   future  capital   expenditures  could   be
   significantly  affected  by  dramatic  swings   in  oil  and  gas   prices,
   unanticipated  delays  in  the initiation  or completion  of  the projects,
   changes   in  governmental   regulations  which   may  affect   permissible
   development, and possible acquisitions or mergers.

      Capital Resources  and Liquidity   The above  forward-looking statements
   generally  estimate  increases in  1996  for  combined  oil,  gas  and  NGL
   production,  and  in  those  expenses  which  affect  operating cash  flow.
   However,  the amount of net cash to  be provided by operating activities in
   1996  is uncertain  due to  the significant  effect of  future oil  and gas
   prices.  It is known, however,  that such cash flow will continue to be the
   primary source  of capital  and liquidity  in 1996.   Operating  cash flow,
   along with working capital and available credit,  are more than adequate to
   meet known capital requirements for 1996.

      Impact of Recently Issued  Accounting Standards  In 1995,  the Financial
   Accounting  Standards  Board  issued  Statement  of   Financial  Accounting
   Standards  No. 121, "Accounting for the Impairment of Long-Lived Assets and
   for  Long-Lived Assets  to  Be  Disposed Of,"  and Statement  of  Financial
   Accounting Standards No.  123, "Accounting  for Stock-Based  Compensation."
   Both  of these statements are effective beginning  in 1996.  With regard to
   oil  and gas  companies, Statement  No.  121 will  have a  more significant
   impact  on  those  companies following  the  successful  efforts method  of
   accounting,  as Statement  No.  121  revises the  "ceiling test"  for  such
   companies.    Statement No.  121  does  not  affect the  ceiling  test  for
   companies  such as  Devon who  follow the full  cost method  of accounting.
   Therefore,  such statement  is not  expected to  have a material  impact on
   Devon's future operations.

      With  regard to  Devon's stock  options granted,  no accounting  is made
   until such time as the options  are exercised.  At that time,  the proceeds
   are added to stockholders' equity, and no expense is recognized.  Statement
   No. 123 provides companies with the option of expensing the "fair value" of
   stock options granted.  Devon will not change its current accounting method
   regarding  stock options, and  therefore Statement No. 123  will not impact
   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 

  Consolidated Financial Statements:
     Consolidated Balance Sheets
          December 31, 1995, 1994 and 1993

     Consolidated Statements of Operations
          Years Ended December 31, 1995, 1994 and 1993

     Consolidated Statements of Stockholders' Equity
          Years Ended December 31, 1995, 1994 and 1993

     Consolidated Statements of Cash Flows
          Years Ended December 31, 1995, 1994 and 1993

     Notes to Consolidated Financial Statements
          December 31, 1995, 1994 and 1993


  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, 1995,  1994 and  1993, and the
  results of their operations  and their cash flows for the years
  then ended,  in conformity  with generally accepted  accounting
  principles.

          As  discussed in  notes  1 and  8  to the  consolidated
  financial  statements,  the  Company  changed  its   method  of
  accounting for income taxes  in 1993 to adopt the provisions of
  Statement   of   Financial  Accounting   Standards   No.   109,
  "Accounting for Income Taxes."



                                            KPMG Peat Marwick LLP

  Oklahoma City, Oklahoma
  February 12, 1996
<PAGE>
<TABLE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
                    Consolidated Balance Sheets

<CAPTION>
                                                        December 31,
                                                1995        1994        1993
  Assets
  Current assets:
            <S>                            <C>            <C>        <C>
            Cash and cash equivalents      $  8,897,891   8,336,371  19,550,288
            Accounts receivable (Note 5)     14,400,295  15,626,799  15,356,653
            Inventories                         605,263     534,326     715,801
            Prepaid expenses                    222,135     564,371     543,166
            Deferred income taxes (Note 8)      749,000     262,000     262,000
              Total current assets           24,874,584  25,323,867  36,427,908
  Property and equipment, at cost, based on
    the full cost method of accounting for oil
    and gas properties (Note 6)             631,437,904 523,941,141 414,073,372
            Less accumulated depreciation,
              depletion and amortization    239,619,167 202,634,961 169,384,351

                                            391,818,737 321,306,180 244,689,021
  Other assets                                4,870,796   4,817,489   4,435,916

              Total assets                 $421,564,117 351,447,536 285,552,845

  Liabilities and stockholders' equity
  Current liabilities:
            Accounts payable:
              Trade                           3,868,458   6,394,897   3,883,775
              Revenues and royalties 
                due to others                 7,322,418   7,398,199  14,679,455
            Income taxes payable              1,364,070           -     467,962
            Accrued expenses                  3,003,943   3,225,493   2,256,583

              Total current liabilities      15,558,889  17,018,589  21,287,775

  Revenues and royalties due to others          816,412   1,383,135   1,445,883
  Other liabilities (Notes 3 and 10)          8,623,057           -           -
  Long-term debt (Note 7)                   143,000,000  98,000,000  80,000,000
  Deferred revenue                               72,761   1,299,947   1,276,640
  Deferred income taxes (Note 8)             34,452,000  27,340,000   8,643,000
  Stockholders' equity (Note 9):
            Preferred stock of $1.00 par value.
              Authorized 3,000,000 shares; 
              none issued                             -           -           -
            Common stock of $.10 par value.  
              Authorized 120,000,000 shares; 
              issued 22,111,896 in 1995,
              22,050,996 in 1994,
              and 20,842,318 in 1993          2,211,190   2,205,100   2,084,232
            Additional paid-in capital      167,430,347 166,654,305 144,403,743
            Retained earnings                49,399,461  37,546,460  26,411,572

              Total stockholders' equity    219,040,998 206,405,865 172,899,547

  Commitments and contingencies (Notes 10
    and 11)
              Total liabilities and
                stockholders' equity       $421,564,117 351,447,536 285,552,845

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

<CAPTION>
                                                         Year Ended December 31,
                                                      1995          1994         1993   
   Revenues
              <S>                                <C>             <C>          <C>
              Oil sales                          $ 55,289,819    38,086,076   38,395,305
              Gas sales                            50,732,158    56,371,452   54,875,796
              Natural gas liquids sales             6,403,663     4,908,126    4,543,625
              Other                                   877,185     1,407,305      942,195

                  Total revenues                  113,302,825   100,772,959   98,756,921

   Costs and expenses
              Lease operating expenses             27,288,755    24,520,757   26,401,597
              Gross production taxes                6,832,507     6,899,743    6,923,535
              Depreciation, depletion and
                amortization (Note 6)              38,089,783    34,132,150   28,409,065
              General and administrative expenses   8,418,739     8,424,687    7,640,210
              Interest expense                      7,051,142     5,438,911    3,421,742

                  Total costs and expenses         87,680,926    79,416,248   72,796,149

   Earnings before income taxes and
              cumulative effect of change in
              accounting principle                 25,621,899    21,356,711   25,960,772

   Income tax expense (Note 8):
              Current                               4,495,000       415,000    1,477,000
              Deferred                              6,625,000     7,197,000    5,298,000

                Total income tax expense           11,120,000     7,612,000    6,775,000

   Earnings before cumulative effect
              of change in accounting principle    14,501,899    13,744,711   19,185,772

   Cumulative effect of change in accounting
              principle (Note 8)                            -             -    1,300,000

   Net earnings                                  $ 14,501,899    13,744,711   20,485,772

   Net earnings per average common
              share outstanding (Note 1):
                Before cumulative effect of
                  change in accounting principle        $0.66          0.64         0.92
                Cumulative effect of change in
                  accounting principle                      -             -         0.06

                Net earnings                            $0.66          0.64         0.98

   Weighted average common shares outstanding      22,073,550    21,551,581   20,822,029


   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,
                                                        1995         1994         1993

  Common stock
             <S>                                  <C>             <C>          <C>
             Balance, beginning of year           $  2,205,100    2,084,232    2,073,298
             Par value of common shares issued           6,090      120,868       10,934

             Balance, end of year                    2,211,190    2,205,100    2,084,232

  Additional paid-in capital
             Balance, beginning of year            166,654,305  144,403,743  143,392,520
             Common shares issued, net
              of issuance costs                        776,042   22,250,562    1,011,223

             Balance, end of year                  167,430,347  166,654,305  144,403,743

  Retained earnings
             Balance, beginning of year             37,546,460   26,411,572    7,801,189
             Dividends                              (2,648,898)  (2,609,823)  (1,875,389)
             Net earnings                           14,501,899   13,744,711   20,485,772
   
             Balance, end of year                   49,399,461   37,546,460   26,411,572

  Total stockholders' equity, end of year         $219,040,998  206,405,865  172,899,547




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

                                                                              
                                                                          Year Ended December 31,
                                                                
                                                                   1995              1994         1993
               <S>                                                 <C>             <C>          <C>

   Cash flows from operating activities:
               Net earnings                                        $  14,501,899   13,744,711   20,485,772
               Adjustments to reconcile net earnings to net
                 cash provided by operating activities:
                   Depreciation, depletion and amortization           38,089,783   34,132,150   28,409,065
                   (Gain) loss on sale of assets                         273,238      (27,086)      34,832
                   Deferred income taxes                               6,625,000    7,197,000    5,298,000
                   Cumulative effect of change in accounting
                     principle                                                 -            -   (1,300,000)
                   Changes in assets and liabilities net of effects
                     of acquisitions of businesses (Note 2):
                        (Increase) decrease in:
                          Accounts receivable                          1,213,877      123,388    2,102,329
                          Inventories                                    (70,937)     181,475     (194,151)
                          Prepaid expenses                               342,236          712     (127,430)
                          Other assets                                   677,238     (489,648)  (1,136,282)
                        Increase (decrease) in:
                          Accounts payable                              (430,736)  (8,896,674)   9,816,309
                          Income taxes payable                         1,364,070     (467,962)    (718,038)
                          Accrued expenses                              (221,550)     997,645    1,201,933
                          Revenues and royalties due to others          (566,723)     (62,748)     (69,763)
                          Long-term other liabilities                    705,636            -            -
                          Deferred revenue                            (1,227,186)     (49,127)     154,234

                          Net cash provided by operating activities   61,275,845   46,383,836   63,956,810

   Cash flows from investing activities:
               Proceeds from sale of property and equipment            9,427,401    4,649,257   11,350,912
               Capital expenditures                                 (117,593,897) (35,619,968) (85,565,098)
               Payments made for acquisition of business (Note 2)     (2,391,484) (42,397,463)           -

                        Net cash used in investing activities       (110,557,980) (73,368,174) (74,214,186)

   Cash flows from financing activities:
               Proceeds from borrowings on revolving line of
                 credit                                               52,000,000   32,500,000   60,000,000
               Principal payments on revolving line of credit         (7,000,000) (14,500,000) (34,900,000) 
               Issuance of common stock, net of issuance costs           782,132      380,244    1,022,157
               Dividends paid on common stock                         (2,648,898)  (2,609,823)  (1,875,389)
               Increase in long-term other liabilities (Note 3)        6,710,421            -            - 

                        Net cash provided by financing activities     49,843,655   15,770,421    24,246,768

   Net increase (decrease) in cash and cash equivalents                  561,520  (11,213,917)   13,989,392

   Cash and cash equivalents at beginning of year                      8,336,371   19,550,288     5,560,896

   Cash and cash equivalents at end of year                        $   8,897,891    8,336,371   19,550,288


   See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  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 a successor to several previous entities
  dating back to 1971.  Devon's common  stock trades on the American
  Stock  Exchange  under the  symbol  "DVN."    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.

               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 


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  1.           Summary   of   Significant   Accounting   Policies
               (Continued)

  Property and Equipment (Continued)

  at 10% per annum, from proved oil, natural  gas and natural gas
  liquids reserves.  Such  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.

               Depreciation  and  amortization of  other property
  and equipment,  including leasehold  improvements, is  provided
  using the straight-line method based on  estimated useful lives
  from 3 to 20 years.

  Deferred Revenue

               Deferred  revenue  includes  funds received  under
  take-or-pay provisions of  certain gas contracts, which provide
  for recovery by the paying party of certain volumes of gas.

  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

               No accounting  is made  with respect  to incentive
  stock options until such time  as they are exercised,  at which
  time the proceeds are added to stockholders' equity.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  1.           Summary   of   Significant   Accounting   Policies
               (Continued)

  Major Purchasers

               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  Energy  Marketing  Corporation ("Aquila")  -  31%;  and
  Enron Gas Marketing, Inc.  ("Enron") - 16%.  During 1994, there
  were  three purchasers  who accounted  for over  10% of Devon's
  gas sales.  These  three purchasers and their  respective share
  of  gas sales were: Aquila - 21%; Enron - 19%; and Meridian Oil
  Trading, Inc. ("MOTI") -  18%.  During 1993, MOTI accounted for
  39% of Devon's gas sales.

  Income Taxes

               Statement  of  Financial Accounting  Standards No.
  109,  "Accounting  for  Income  Taxes"  ("Statement  109")  was
  issued in  February 1992.    Under  Statement 109's  asset  and
  liability  method,  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  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.  Under
  Statement  109,   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.

               Devon  adopted Statement 109  effective January 1,
  1993, and has  reported a benefit of $1.3  million in 1993 as a
  cumulative effect of a change in accounting principle.

  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

               Net earnings  per common share are  based upon the
  weighted average number  of shares of common stock  outstanding
  during the year.  Stock  options have been excluded  since they
  would not have had a significant dilutive effect.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  1.           Summary   of   Significant   Accounting   Policies
               (Continued)

  Dividends

               Beginning   with  the  second   quarter  of  1993,
  dividends on common stock were  paid in 1993, 1994 and 1995  at
  a per share rate of $0.03 per quarter.

  Fair Value of Financial Instruments

               Devon's  only financial  instrument for  which the
  fair value differs  materially from the carrying  value is  the
  interest  rate swap discussed  in Note  7.  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 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. 

  2.           Acquisitions and Pro Forma Information

               On  December  18,  1995,  Devon  acquired  certain
  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 estimated reserve quantities acquired were
  1.8 million  barrels of oil, 59  billion cubic  feet of natural
  gas and  3.7 million barrels of  oil equivalent  of natural gas
  liquids.    Included  in  these  reserves  are  certain  proved
  undeveloped  reserves,  for   which  Devon  expects  to   incur
  approximately  $11.8   million   of   future   capital   costs.
  Approximately $4.0 million of the purchase  price was allocated
  to undeveloped leasehold.   (The quantities of proved  reserves
  and  the estimated  future  development  costs stated  in  this
  paragraph are unaudited.)

               On  February  18,  1994,  Devon  and  Alta  Energy
  Corporation  ("Alta") entered  into an  Agreement  and Plan  of
  Merger, as amended on April  13, 1994, whereby Alta  was merged
  into a wholly-owned subsidiary  of Devon  (the "Merger").   The
  Merger  was consummated  on  May 18,  1994,  at which  date the
  separate existence of Alta ceased.   Alta's common stockholders
  received approximately 1,168,000 shares  of Devon common  stock
  and $1.5  million  in  cash upon  consummation  of the  Merger.
  Subsequently,   in  February  1995,  former  Alta  stockholders
  received an additional cash payment  of $2.4 million based upon
  the evaluation of the  Camille Adams #1 well in Louisiana which
  Alta  completed during  the  first half  of  1994.   Devon also
  incurred $41.4 million of  other costs  related to the  Merger.
  This included $31.7 million to


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  2.           Acquisitions and Pro Forma Information (Continued)

  acquire  Alta's  debt  from  its  creditors;  $3.0  million  to
  acquire  shares  of  Alta  preferred  and  common  stock;  $3.8
  million loaned  to Alta  for operating funds;  $1.5 million  to
  acquire certain net profits interests from  Alta creditors; and
  $1.4 million for third party costs related to the Merger.

               Devon recorded additional deferred tax liabilities
  of  $11.5 million  due to the  substantially tax-free nature of
  the  Merger to  the  former Alta  stockholders.   Excluding the
  $11.5   million   of   additional  deferred   tax  liabilities,
  approximately  $69.4   million  of   the  total   consideration
  involved in  the Merger  was allocated  to proved  oil and  gas
  reserves.    Including  the  deferred  tax  liabilities,  $80.9
  million was allocated to proved oil and gas reserves.

               On June 28, 1993, Devon acquired certain coal seam
  natural gas  properties in  the San  Juan Basin  of New  Mexico
  ("the Acquired San  Juan Basin  Properties") for  approximately
  $53.3 million.   Approximately  $48.3 million  of the  purchase
  price  was  attributable  to  proved  coal   seam  natural  gas
  reserves.  The remaining $5  million of the purchase  price was
  allocated to unproved  reserves associated with infill drilling
  and development rights.   The acquisition was primarily  funded
  with $50 million of  borrowings from Devon's credit lines.  The
  acquisition  was  accounted  for  by  the  purchase  method  of
  accounting  for  business  combinations.     Accordingly,   the
  accompanying  1993 consolidated  statement of  operations  does
  not  include  any  revenues or  expenses  associated  with  the
  Acquired San Juan Basin Properties prior to July 1, 1993.

  Pro Forma Information (Unaudited)

               The 1995 acquisition of  the Worland Properties as
  described above  was accounted  for by the  purchase method  of
  accounting  for  business  combinations.     Accordingly,   the
  accompanying  1995 consolidated  statement of  operations  does
  not  include  any  revenues or  expenses  associated  with  the
  Worland Properties prior  to the closing date  of December  18,
  1995.    Following  are Devon's  pro  forma  results  for  1995
  assuming the acquisition occurred at the beginning of 1995:
<TABLE>
<CAPTION>
                                               1995

                         <S>               <C>
                    Total revenues         $118,652,000
                    Net earnings            $13,097,000
                    Net earnings per share        $0.59
</TABLE>
               The  1994 Merger 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 Alta prior to  the closing date of May  18,
  1994.   Following  are Devon's pro  forma 1994 results assuming
  the acquisition  of the Worland Properties  and the Merger both
  occurred on January 1, 1994:


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  2.           Acquisitions and Pro Forma Information (Continued)

  Pro Forma Information (Unaudited) (Continued)

<TABLE>
<CAPTION>
                                                                   1994
                                                            Pro Forma Effect of
                                              Devon                    Worland       Devon
                                            Historical      Merger    Properties   Pro Forma

                  <S>                      <C>            <C>         <C>         <C>
                  Total revenues           $100,773,000   4,329,000   6,297,000   111,399,000
                  Net earnings              $13,745,000    (329,000)   (387,000)   13,029,000
                  Net earnings per share          $0.64       (0.03)       (.02)         0.59
</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  Internal Revenue  Service
  regulations.   Consequently, gas produced from these properties
  through  the year  2002 qualifies  for Section 29  tax credits,
  which  as of  year-end 1995  were equal  to approximately $1.01
  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.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  3.           San Juan Basin Transaction (Continued)

               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  will continue  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 12 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 year  ended  December  31,  1995,  Devon
  received  $13.9  million  related  to the  credits.    Of  this
  amount, $12.8  million was  recorded as  additional gas  sales,
  and $1.1 million was  recorded as an addition to liabilities as
  discussed in the  following paragraph.  *Based  on the  reserves
  estimated  at  December   31,  1995,  and  an  assumed   annual
  inflation  factor of 2%, Devon  estimates it will receive total
  tax  credit payments  of approximately  $68  million from  1996
  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  will be  increased over  time to  reflect the option
  purchase price.  As  the purchase price increases, a portion of
  the tax credit payments received  by Devon will be added to the
  liability.   As stated above, for  the year  ended December 31,
  1995, $1.1 million of  the total amount received for tax credit
  payments  was  added   to  the  liability,  which  raised   the
  liability balance to $6.7 million.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  3.           San Juan Basin Transaction (Continued)

               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   $6.7  million  of   other
  liabilities  recorded as of year-end 1995, does not include any
  amount related to such reserves.

  4.           Supplemental Cash Flow Information

               Cash payments for interest in 1995, 1994, and 1993
  were   approximately  $6.7  million,  $5.1   million  and  $3.3
  million, respectively.   Cash  payments for  federal and  state
  income  taxes in  1995, 1994, and  1993 were approximately $2.2
  million, $1.8 million and $2.3 million, respectively.

               The  Merger with  Alta in  1994 involved  cash and
  non-cash consideration as presented below:

<TABLE>
<CAPTION>
                                                                 1994

                         <S>                                  <C>
                         Cash payments made                   $42,915,845
                         Value of common stock issued          21,991,084
                         Liabilities assumed                    7,192,671
                         Deferred tax liability created        11,500,000

                         Fair value of assets acquired        $83,599,600
</TABLE>
               The above  cash payments of $42.9  million include
  approximately  $1.4  million  of direct  costs  paid  to  third
  parties which were  capitalized and allocated to producing  oil
  and gas properties.  The  cash payments made are reduced in the
  accompanying  1994  consolidated  statement  of cash  flows  by
  $518,382 of cash acquired in the Merger.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  5.           Accounts Receivable

               The components of accounts receivable included the
  following:

<TABLE>
<CAPTION>
                                                       December 31,           
                                              1995         1994         1993


     Oil, gas and natural gas liquids
        <S>                               <C>           <C>          <C>
        revenue accruals                  $11,169,313   10,973,589   11,981,969
     Joint interest billings                2,962,037    3,367,493    2,995,440
     Income tax refunds due                         -      959,085            -
     Other                                    493,945      551,632      629,244

                                           14,625,295   15,851,799   15,606,653
     Allowance for doubtful accounts         (225,000)    (225,000)    (250,000)

     Net accounts receivable              $14,400,295   15,626,799   15,356,653 
</TABLE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  6.      Property and Equipment
<TABLE>
     Property and equipment included the following:
                                                                
<CAPTION>
                                                        December 31,
                                              1995          1994           1993
     Oil and gas properties:
          <S>                            <C>             <C>           <C>
          Subject to amortization        $ 604,227,702   503,174,488   394,845,195
          Not subject to amortization:
               Acquired in 1995              5,635,170             -             -
               Acquired in 1994              1,001,427     1,451,109             -
               Acquired in 1993              5,556,977     5,556,977     5,993,090
               Acquired in 1992              8,257,985     8,561,031     8,650,308

          Accumulated depreciation,
               depletion and amortization (237,385,785) (200,746,032) (167,884,858)

                 Net oil and gas
                   properties              387,293,476   317,997,573   241,603,735

     Other property and equipment:
          Computers, office equipment,
               furniture and leasehold
               improvements                  5,168,817     4,047,183     3,645,091
          Automotive equipment               1,201,084       786,338       646,247
          Other                                388,742       364,015       293,441

                                             6,758,643     5,197,536     4,584,779
          Accumulated depreciation and
               amortization                 (2,233,382)   (1,888,929)   (1,499,493)

                 Net other property and
                   equipment                 4,525,261     3,308,607     3,085,286

     Property and equipment, net of
          accumulated depreciation,
          depletion and amortization     $ 391,818,737   321,306,180   244,689,021
</TABLE>
<TABLE>
     Depreciation, depletion and  amortization expense  consisted
  of the following components:

<CAPTION>
                                                  Year Ended December 31,   
                                             1995           1994            1993
       <S>                               <C>             <C>            <C>

     Depreciation, depletion and
       amortization of oil and gas
       properties                        $36,639,753     32,861,174     27,419,640
     Depreciation and amortization of
       other property and equipment        1,045,978        865,092        808,770
     Amortization of other assets            404,052        405,884        180,655

          Total expense                  $38,089,783     34,132,150     28,409,065 
</TABLE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  7.      Long-term Debt

     Devon has 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, 1995, was $205
  million.  In 1996,  the banks revised the Borrowing Base upward
  to $260 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  plus  up to  .75%  depending  on  the  percentage of  the
  Borrowing Base that  is borrowed.  The  average interest  rates
  on the  outstanding debt  at the  end of  1995, 1994  and 1993,
  were  6.64%,   6.83%  and  4.16%,   respectively.    The   loan
  agreements also  provide for a  quarterly commitment fee  equal
  to .375% per annum.

     Debt  borrowed  under the  credit  lines is  unsecured.   No
  principal  payments  are  required  until  maturity unless  the
  unpaid balance exceeds the  Borrowing Base.  As of December 31,
  1995, $140 million of the  outstanding balance matures on March
  31, 1998, and the remaining $3 million matures  on May 1, 1997.
  The   loan    agreements   contain    certain   covenants   and
  restrictions,  among  which  are   limitations  on   additional
  borrowings and  sales of  properties valued  at  more than  $10
  million,    working   capital   and   net   worth   maintenance
  requirements  and  a minimum  debt  to  net  worth  ratio.   At
  December  31, 1995, Devon was in compliance with such covenants
  and restrictions.

     Assuming the Borrowing Base is not reduced below the current
  loan balance  outstanding and  the maturity dates  of the loans
  are not extended,  the debt outstanding at  the end of 1995  is
  scheduled to be payable as follows:
<TABLE>
<CAPTION>
          Year ending December 31,

              <S>       <C>         
              1996      $           -   
              1997          3,000,000
              1998        140,000,000

                         $143,000,000
</TABLE>
     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 principal  amount of the
  swap  agreement is  $75  million, and  the  other party  to the
  agreement is one of the lenders of Devon's


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  7.      Long-term Debt (Continued)

  credit lines (the  "Lender").  The agreement terminates on June
  16, 1998, unless the Lender  exercises its right to  extend the
  termination date to June 16,  2000.  The terms of the agreement
  provide  for  quarterly  payments  either  to  or  from  Devon,
  determined by whether the three month  London Interbank Offered
  Rate  ("LIBOR") in effect  at the  beginning of  each quarterly
  calculation  period  is  greater  or  less  than   5.6%.    The
  calculation periods begin on  the sixteenth day of each  March,
  June,  September and December during the term of the agreement.
  If, on the date of  the beginning of the  quarterly calculation
  period, the  three month LIBOR  exceeds 5.6%,  the Lender  will
  owe Devon  the quarterly amount of  the excess  rate applied to
  the $75  million principal.   Alternately,  if the three  month
  LIBOR  on the  applicable  quarterly  date is  less  than 5.6%,
  Devon will owe the Lender.

     The swap agreement  is accounted  for as a  hedge, with  the
  amount  which is  either due  to  or from  Devon recorded  as a
  reduction or increase  in interest  expense.   The three  month
  LIBOR  exceeded 5.6%  at  the beginning  of  each of  the three
  quarterly  calculation  periods  in  1995.    Therefore,  Devon
  recognized  $0.1 million as a  reduction to interest expense in
  1995.   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 has no  carrying value in the  accompanying
  consolidated financial statements.

     The swap agreement  does not  alter or affect  any terms  or
  conditions of Devon's credit lines.

  8.      Income Taxes

     At December 31, 1995,  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             1996-2008        $15,400,000
     Net operating loss - various states      1996-2010        $18,100,000
     Statutory depletion                         N/A           $ 6,500,000
     Minimum tax credit                          N/A           $ 5,600,000
     Investment tax credit                    1996-1999        $   100,000
</TABLE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  8.      Income Taxes (Continued)

     All  of  the  carryforward  amounts shown  above  have  been
  utilized  for  financial  purposes  to reduce  deferred  taxes.
  Substantially   all  of   the   federal  net   operating   loss
  carryforwards shown above were acquired in the 1994 Merger.

     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,     
                                               1995       1994     1993
     <S>                                        <C>        <C>      <C>

     Federal statutory tax rate                 35%        35%      35%
     Nonconventional fuel source credits        (1)         -       (6)
     Alternative minimum tax (credit)            -          -       (2)
     State income taxes                          4          3        1
     Effect of San Juan Basin Transaction        4          -        -
     Other                                       1         (2)      (2)

     Effective income tax rate                  43%        36%      26%
</TABLE>

     As  discussed in Note 1,  Devon adopted Statement  109 as of
  January 1, 1993.  The  $1.3 million cumulative benefit  of this
  change   is  reported  separately   in  the  1993  consolidated
  statement of operations.

     The tax effects of temporary  differences that gave rise  to
  significant  portions   of   the   deferred  tax   assets   and
  liabilities at  December 31, 1995, 1994  and 1993,  as provided
  for under Statement 109, are presented below:


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  8.      Income Taxes (Continued)
<TABLE>
<CAPTION>
                                                                
                                                                  December 31,            
                                                        1995          1994         1993

     Deferred tax assets:
          <S>                                      <C>             <C>         <C>
          Net operating loss carryforwards         $  6,082,000    6,127,000   1,609,000
          Statutory depletion carryforwards           2,287,000    3,087,000   2,606,000
          Investment tax credit carryforwards            85,000      813,000     894,000
          Minimum tax credit carryforwards            5,576,000    2,195,000   1,860,000
          Production payments                        24,770,000            -           -
          Other                                       1,966,000      897,000     629,000

               Total gross deferred tax assets       40,766,000   13,119,000   7,598,000
               Less valuation allowance                 100,000      100,000           -

               Net deferred tax assets               40,666,000   13,019,000   7,598,000
     Deferred tax liabilities:
          Property and equipment, principally due
               to differences in depreciation, and
               the expensing of intangible drilling
               costs for tax purposes               (74,369,000) (40,097,000) (15,979,000)

                 Net deferred tax liability        $(33,703,000) (27,078,000)  (8,381,000)
</TABLE>
     As shown in the  above schedule, Devon has recognized  $40.7
  million  of net  deferred tax assets  as of  December 31, 1995.
  Such amount consists almost entirely of $14 million  of various
  carryforwards  available  to offset  future  income  taxes, and
  $24.8  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  2006,  state  net  operating  loss  carryforwards  which
  expire primarily between  1999 and 2003, investment tax  credit
  carryforwards  which expire  between  1996  and 1999,  and  the
  statutory depletion and  minimum tax credit carryforwards which
  have no expiration dates.   Statement 109 requires that the tax
  benefit of carryforwards be  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",  Statement  109  requires  that   a
  valuation  allowance be  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 1996  and  2002.   Such
  expectation is based  upon current estimates of taxable  income
  during  this  period,  considering  limitations on  the  annual
  utilization of these benefits as set forth


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  8.      Income Taxes (Continued)

  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,  1995, related to
  depletion carryforwards acquired in the Merger.

     The  $24.8  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 recognized, and  the present  value of  the
  production  payments to  be  received was  recorded as  a  note
  receivable.   For  presentation  purposes,  the  $24.8  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.      Stockholders' Equity

     The  authorized  capital  stock  of Devon  consists  of  120
  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, 1995, 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.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  9.      Stockholders' Equity (Continued)

  Stock Option Plans

     Prior to 1993, Devon had outstanding stock options issued to
  certain  of its employees under  two stock option plans adopted
  in  1987  and 1988  ("the  1987  Plan"  and  "the 1988  Plan").
  During 1993, all  remaining options outstanding under the  1987
  Plan  were exercised.    Also during  1993,  the 1988  Plan was
  cancelled.    Options  granted  under  the   1988  Plan  remain
  exercisable by the  employees owning  such options, but  no new
  options will be granted  under the 1988 Plan.  At  December 31,
  1995, 14  participants  held  the 368,600  options  outstanding
  under the 1988 Plan.

     Effective  June  7, 1993,  Devon  adopted  the Devon  Energy
  Corporation  1993  Stock  Option Plan  ("the  1993  Plan")  and
  reserved  one  million  shares of  Common  Stock  for  issuance
  thereunder  to  key   management  and  professional  employees.
  Eighteen such  employees were  eligible to  participate in  the
  1993 Plan at year-end 1995.

     The exercise price of  incentive stock options granted under
  the 1993  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.   The  exercise price  of
  nonqualified  options granted  under the  1993 Plan may  not be
  less than  75% of  the fair market  value of  the stock on  the
  date of 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  1993   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 1993 Plan  is administered  by a committee
  comprised of non-management members of the  Board of Directors.
  The 1993 Plan expires  on April 25,  2003.  As of  December 31,
  1995,  18  participants held  the  660,300  options outstanding
  under the 1993 Plan.   There were 337,200 options available for
  future grants as of December 31, 1995.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  9.      Stockholders' Equity (Continued)

     Stock Option Plans (Continued)

     A summary of  the status of Devon's stock option plans as of
  December 31,  1993, 1994 and 1995,  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, 1992        377,537   $10.146

     Options granted                  214,500   $24.087
     Options exercised               (109,337)  $ 9.349

  Balance at December 31, 1993        482,700   $16.521      300,000   $14.848

     Options granted                  436,000   $20.736
     Options exercised                (40,800)  $ 9.355

  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 
</TABLE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  9.      Stockholders' Equity (Continued)

      Stock Option Plans (Continued)

     The  following table  summarizes  information about  Devon's
  stock  options which  were outstanding,  and  those which  were
  exercisable, as of December 31, 1995:
<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   

  <C>            <C>        <C>         <C>         <C>       <C>
  $8 to $14      168,600    5.3 years   $10.001     154,600   $10.148
  $18 to $21     210,800    8.9 years   $18.088     121,600   $18.089
  $23 to $25     649,500    8.7 years   $23.770     412,600   $23.827

  $8 to $25    1,028,900    8.2 years   $20.349     688,800   $19.744
</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.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993



  10.     Retirement Plans

     Devon  has a  defined  benefit retirement  plan (the  "Basic
  Plan")  which is  non-contributory  and  includes substantially
  all  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, 
                                               1995          1994           1993
     Actuarial present value of benefit
        obligations:
          Accumulated benefit obligation:
            <S>                             <C>           <C>           <C>
            Vested                          $(3,500,000)  (2,648,000)   (2,737,000)
            Nonvested                          (654,000)    (282,000)     (394,000)

            Total                           $(4,154,000)  (2,930,000)   (3,131,000)

          Projected benefit obligation for
             service rendered to date        (4,782,000)  (3,378,000)   (3,624,000)
     Plan assets at fair value, primarily
          investments in corporate obligation
          and equity mutual funds             4,227,000    3,252,000     2,917,000

     Plan assets less than projected benefit
          obligation                           (555,000)    (126,000)     (707,000)
     Unrecognized prior service cost
          (benefit)                            (154,000)    (176,000)     (123,000)
     Unrecognized net loss from past experience
       different from that assumed, and effects
       of changes in assumptions                921,000      225,000       683,000
     Unrecognized net transitional asset              -            -       (35,000) 

     Prepaid (accrued) pension expense    $     212,000      (77,000)     (182,000) 

</TABLE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  10.     Retirement Plans (Continued)

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

     Actuarial present value of benefit obligations:
          Accumulated benefit obligation:
            <S>                                                <C>
            Vested                                             $(1,658,000)
            Nonvested                                             (255,000)

            Total                                              $(1,913,000)

          Projected benefit obligation for service rendered
            to date                                             (2,245,000)
     Plan assets at fair value                                           -

     Projected benefit obligation in excess of plan assets      (2,245,000)
     Unrecognized prior service cost                             1,354,000
     Unrecognized net loss from past experience different
          from that assumed, and effects of changes in
          assumptions                                              185,000

     Accrued pension expense                                      (706,000)
     Additional minimum liability                               (1,207,000)

     Total pension liability                                   $(1,913,000)
</TABLE>
            The  $1.9  million  total  pension liability  of  the
  Supplementary Plan is  included in long-term other  liabilities
  on  the accompanying  consolidated  balance  sheet.   The  $1.2
  million  additional  minimum  liability is  offset  by  a  $1.2
  million  intangible  asset  included in  other  assets  on  the
  balance sheet.

            Net pension  expense for Devon's  two defined benefit
  plans included the following components:
                                                                
<TABLE>
<CAPTION>
                                                                Year Ended December 31, 
                                                              1995       1994       1993 
     <S>                                                   <C>          <C>       <C>

     Service cost - benefits earned during the period      $ 362,000    277,000   183,000
     Interest cost on projected benefit obligation           446,000    284,000   247,000
     Actual return on plan assets                           (536,000)   (20,000) (254,000)
     Net amortization and deferral                           345,000   (231,000)  101,000

     Net periodic pension expense                          $ 617,000  310,000     277,000
</TABLE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  10.     Retirement Plans (Continued)

     The weighted  average discount rate used  in determining the
  actuarial present value of the projected  benefit obligation in
  1995, 1994  and 1993 was  7.25%, 8.5% 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 8.50% in 1995 and 8% in 1994 and 1993.

     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
  $170,000, $158,000  and $147,000 for  the years ended  December
  31, 1995, 1994 and 1993, respectively.

  11.     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 majority  of Devon's  sales of nonconventional  gas from
  the  San   Juan  Basin   are  subject   to  federal   royalties
  administered and  collected by the  Minerals Management Service
  ("MMS").   In determining  royalties payable to  the MMS, Devon
  has followed the industry  practice of  reducing the gas  sales
  price   for   certain   permitted   costs    related   to   the
  transportation of gas produced  and CO 2 removal.  In  1995, the
  MMS issued new policies  which would increase Devon's share  of
  federal royalties for nonconventional gas produced  and sold in
  the San  Juan Basin for  the years 1990  through 1995, and  for
  future years as  well.  While the MMS  has not asserted a claim
  for   additional  royalties,   and   while  Devon   intends  to
  vigorously contest any  claim for excessive additional  federal
  royalties   through   available  administrative   and  judicial
  processes, Devon has accrued an estimate  of additional federal
  royalties  related to  its  share  of gas  produced  from  1990
  through 1995.   Devon's management, in consultation with  legal
  counsel,  believes adequate  provision has  been  made for  any
  additional federal  royalties due  and related  interest.   The
  amount accrued represents  Devon's best estimate of the  amount
  likely   to  be   assessed  by   the  MMS   based  on   Devon's
  interpretation  of  the  new  policies  issued  and  all  other
  related information available to  Devon.  It is possible that a
  different  interpretation  of  the policies  and  related facts
  could  result in  an  assessment  higher than  what  Devon  has
  accrued.   However, Devon's  management does  not believe  that
  the amount of  possible assessments above that already  accrued
  would be material.


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  11.     Commitments and Contingencies (Continued)

     In  a matter unrelated to the MMS issue discussed above, 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 the assessment in  January 1996 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 CO 2.  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.   If the  amount paid  is not  refunded
  through the  normal administrative  processes available,  Devon
  intends  to  file  a  suit   asking  that  the  assessments  be
  reversed.  At  this time, it is  not possible to determine  the
  eventual outcome of  this matter.  However, Devon's  management
  and legal counsel  believe that it is  reasonably possible that
  the amount  paid to the State  of New Mexico  will be refunded.
  Pending further  developments on  this matter,  Devon will  not
  expense in  its financial statements  the taxes, penalties  and
  interest  paid,  but   rather  will  record  such  amounts   as
  receivables.

     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, 1995:
<TABLE>
<CAPTION>
          Year ending December 31,
              <C>                                         <C>
              1996                                        $543,000
              1997                                         136,000
              1998                                          83,000
              1999                                          39,000
              2000                                          26,000

                  Total minimum lease payments required   $827,000
</TABLE>
     Total rental expense for all  operating leases is as follows
  for the years ended December 31:
<TABLE>
              <S>     <C>
              1995    $546,388
              1994    $521,769
              1993    $487,554
</TABLE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  12.     Oil and Gas Operations

  Costs Incurred

     The following table  reflects the costs incurred  in oil and
  gas   property   acquisition,  exploration,   and   development
  activities:
<TABLE>
<CAPTION>
                                                   Year Ended December 31,
                                               1995          1994         1993

     Property acquisition costs:
          Proved, excluding deferred income
            <S>                             <C>           <C>          <C>
            taxes                           $47,316,000   70,376,000   49,790,000
          Deferred income taxes                       -   11,500,000            -

          Total proved, including deferred income 
            taxes                           $47,316,000   81,876,000   49,790,000

          Unproved                          $ 4,529,000    1,797,000    6,444,000
     Exploration costs                      $ 7,174,000    5,194,000    4,115,000
     Development costs                      $56,253,000   26,268,000   25,748,000
</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 table,  were $2.7
  million, $2.3 million and  $2.2 million in the years 1995, 1994
  and 1993, respectively.

     Due to the substantially tax-free nature of  the 1994 Merger
  to the  former  Alta  stockholders, Devon  recorded  additional
  deferred tax liabilities of $11.5  million as of the  effective
  date  of the  Merger.  The  deferred tax  liabilities caused an
  additional $11.5 million to  be allocated to proved oil and gas
  reserves in 1994 as shown in the above schedule.

  Results of Operations for Oil and Gas Producing Activities

     The  following   table   includes  revenues   and   expenses
  associated  directly  with  Devon's   oil  and  gas   producing
  activities.   It does  not include  any  allocation of  Devon's
  interest costs  or general corporate  overhead and,  therefore,
  is  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:


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  12.     Oil and Gas Operations (Continued)

  Costs Incurred (Continued)
<TABLE>
<CAPTION>
                                                        Year Ended December 31,
                                                    1995          1994         1993
     <S>                                        <C>            <C>          <C>
     Oil, gas and natural gas liquids sales     $112,425,000   99,366,000   97,815,000
     Production and operating expenses           (34,121,000) (31,421,000) (33,325,000)
     Depreciation, depletion and amortization    (36,640,000) (32,861,000) (27,420,000)
     Income tax expense                          (15,536,000) (12,411,000) (12,844,000)

     Results of operations for oil and gas
          producing activities                  $ 26,128,000   22,673,000   24,226,000

     Depreciation, depletion and amortization
          per equivalent barrel of production          $3.65         3.45         3.16

</TABLE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  13.     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, 1995,
  as  estimated  by  Devon's  independent  petroleum  consultants
  LaRoche  &  Associates, and  Devon's  own  petroleum engineers.
  Approximately  92%, 91%,  and 95%  of  the respective  year-end
  1995, 1994 and 1993 proved reserves were calculated  by LaRoche
  & Associates.   The remaining percentage  of reserves are based
  on Devon's own  estimates.  Natural gas liquids are denominated
  in barrels of oil equivalent  ("Boe") and are converted  to Boe
  using the ratio  of 42 gallons to  one barrel.  All of  Devon's
  reserves are located within the United States.
<TABLE>
<CAPTION>
                                                                          Natural
                                                   Oil         Gas     Gas Liquids
                                                  (Bbls)      (Mcf)        (Boe)

  <S>                                          <C>         <C>          <C>
  Proved reserves as of December 31, 1992      16,349,000  263,598,000  1,011,000
     Revisions of estimates                      (995,000)  54,536,000  1,227,000
     Extensions and discoveries                 3,543,000   20,759,000     80,000
     Purchase of reserves                         363,000   75,168,000     20,000
     Production                                (2,337,000) (35,598,000)  (411,000)
     Sale of reserves                          (2,026,000)  (9,209,000)   (73,000)

  Proved reserves as of December 31, 1993      14,897,000  369,254,000  1,854,000
     Revisions of estimates                     3,157,000   (5,540,000) 1,733,000
     Extensions and discoveries                 2,008,000   13,206,000    183,000
     Purchase of reserves                      25,201,000   13,492,000  2,181,000
     Production                                (2,467,000) (39,335,000)  (501,000)
     Sale of reserves                            (631,000)  (3,517,000)    (8,000)

  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

  Proved developed reserves as of:
     December 31, 1992                         13,823,000  249,154,000    797,000
     December 31, 1993                         11,548,000  355,536,000  1,751,000
     December 31, 1994                         18,718,000  324,302,000  3,123,000
     December 31, 1995                         28,703,000  311,664,000  6,149,000

</TABLE>
<PAGE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  13.     Supplemental  Information on  Oil  and  Gas  Operations
          (Unaudited) (Continued)

  Standardized Measure of Discounted Future Net Cash Flows

     The accompanying table reflects the standardized measure  of
  discounted future net  cash flows relating to Devon's  interest
  in proved reserves:
<TABLE>
<CAPTION>
                                                      December 31,
                                          1995           1994           1993

     <S>                            <C>              <C>             <C>
     Future cash inflows            $1,476,418,000   1,186,845,000   913,931,000
     Future costs:
          Development                  (52,327,000)    (75,115,000)  (23,713,000)
          Production                  (496,279,000)   (400,676,000) (256,658,000)
     Future income tax expense        (153,431,000)    (71,427,000)  (61,480,000)

     Future net cash flows             774,381,000     639,627,000   572,080,000
     10% discount to reflect timing of
          cash flows                  (328,481,000)   (281,421,000) (228,530,000)

     Standardized measure of discounted
          future net cash flows     $  445,900,000     358,206,000   343,550,000

     Discounted future net cash
          flows before income taxes $  534,248,000     398,206,000   380,471,000
</TABLE>
     Future cash inflows are computed by applying year-end prices
  (averaging   $18.11   per   barrel   of   oil,   adjusted   for
  transportation  and other  charges, $1.35  per Mcf  of gas  and
  $12.73 per Boe of natural gas  liquids at December 31, 1995) 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 $1.35 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 cash  inflows shown  in the table
  above  include  $58.2  million  related  to  these  tax  credit
  payments  from  1996  through  2002.    This  amount  has  been
  calculated  using the  assumption that  the  year-end 1995  tax
  credit  rate of  $1.01  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.  Prior to the San
  Juan Basin


             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  13.     Supplemental  Information on  Oil  and  Gas  Operations
  (Unaudited) (Continued)

  Standardized  Measure  of  Discounted  Future  Net  Cash  Flows
  (Continued)

  Transaction  as described  in  Note  3, the  future  income tax
  expenses estimated at December 31,  1994 and 1993 were  reduced
  by the estimated future  Section 29 tax credits to be generated
  by  the San  Juan  Basin coal  seam  gas  properties.   It  was
  estimated at year-end  1994 and 1993 that undiscounted  amounts
  of approximately $113  million and $137 million,  respectively,
  of Section  29 tax credits could  be generated  in future years
  to Devon's  interest.  However,  because of limitations on  the
  amount  of  Section  29  tax  credits  which  can  actually  be
  utilized  for  income tax  purposes,  the undiscounted  amounts
  included  as  reductions  to  future  income  tax  expense  for
  purposes of calculating the standardized measure of  discounted
  future net cash flows were only $41 million and $39 million  at
  year-end 1994 and 1993,  respectively.  As a result  of the San
  Juan Basin Transaction, substantially  all of the value  of the
  Section 29  tax credits  at year-end  1995 is  now included  in
  "future cash  inflows," instead  of a reduction  to income  tax
  expense,  in Devon's standardized measure  of discounted future
  net cash flows.

  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,
                                                       1995         1994           1993

          <S>                                     <C>            <C>           <C>
          Beginning balance                       $358,206,000   343,550,000   286,693,000
          Sales of oil, gas and natural gas
             liquids, net of production costs      (78,304,000)  (67,945,000)  (64,490,000)
          Net changes in prices and
             production costs                       60,498,000  (107,210,000)    1,479,000
          Extensions, discoveries, and improved
             recovery, net of future
             development costs                      22,308,000    14,629,000    26,999,000
          Purchase of reserves, net of future
             development costs                      50,000,000   133,103,000    59,594,000
          Development costs incurred during
             the period which reduced future
             development costs                      43,810,000    16,519,000    11,580,000
          Revisions of quantity estimates            7,397,000    26,167,000    47,798,000
          Sales of reserves in place               (7,933,000)    (5,281,000)  (18,170,000)
          Accretion of discount                    39,821,000     38,047,000    31,457,000
          Net change in income taxes              (48,347,000)    (3,080,000)   (9,048,000)
          Other, primarily changes in timing       (1,556,000)   (30,293,000)  (30,342,000)

          Ending balance                         $445,900,000    358,206,000   343,550,000
</TABLE>
<PAGE>

             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1995, 1994 and 1993


  14.     Supplemental Quarterly Financial Information (Unaudited)

     Following  is a summary of  the unaudited interim results of
  operations for the years ended December 31, 1995 and 1994:
<TABLE>
<CAPTION>
<F1>
                                     1995 - Actual Reported Results (a)
                                 First       Second       Third      Fourth
                                Quarter      Quarter     Quarter     Quarter       Total

   Oil, gas and natural gas
      <S>                     <C>          <C>         <C>         <C>         <C>
      liquids sales           $23,519,568  25,331,966  33,589,019  29,985,087  112,425,640
   Total revenues             $23,762,327  25,650,334  33,770,864  30,119,300  113,302,825
   Net earnings               $ 1,026,802   2,444,422   6,645,531   4,385,144   14,501,899
   Net earnings per share           $0.05        0.11        0.30        0.20         0.66
</TABLE>
<TABLE>
<CAPTION>
<F1>
                                      1995 - Adjusted Results (a)
                                First       Second       Third       Fourth
                               Quarter      Quarter     Quarter      Quarter       Total

   Oil, gas and natural gas
      <S>                    <C>          <C>         <C>          <C>         <C>
      liquids sales          $26,478,770  28,293,715  27,668,068   29,985,087  112,425,640
   Total revenues            $26,796,579  28,612,083  27,774,863   30,119,300  113,302,825
   Net earnings              $ 2,864,127   4,181,531   3,071,097    4,385,114   14,501,899
   Net earnings per share          $0.13        0.19        0.14         0.20         0.66

<F1>
   (a)      The San Juan Basin  Transaction described in Note 3  was effective
   January  1,  1995.    However, it  was  initially  subject  to  a  material
   contingency,  and thus  the  transaction's impact  on Devon's  statement of
   operations was  deferred pending  the contingency's  resolution.  When  the
   contingency was favorably resolved, the cumulative nine-month effect of the
   transaction  was  recorded in  the third  quarter.   The first  table above
   includes the  1995 quarterly results as  reported, including the  six-month
   out-of-period effect on the third quarter.  The second table above presents
   the quarterly results as they  would have been reported had the contingency
   not  existed and had  the San  Juan Basin Transaction's  effect on earnings
   been reported from the inception of the transaction on January 1, 1995.
</TABLE>
<TABLE>
<CAPTION>
                                                      1994
                                 First       Second       Third       Fourth
                                Quarter      Quarter     Quarter      Quarter      Total

   Oil, gas and natural gas 
      <S>                     <C>          <C>         <C>         <C>         <C>
      liquids sales           $25,778,304  24,953,045  25,054,238  23,580,067  99,365,654
   Total revenues             $26,144,281  25,519,353  25,298,970  23,810,355 100,772,959
   Net earnings               $ 4,876,974   4,053,853   3,055,972   1,757,912  13,744,711
   Net earnings per share           $0.23        0.19        0.14        0.08        0.64
</TABLE>
<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 29,
   1996.


   ITEM 11.    EXECUTIVE COMPENSATION

               The information called for by this Item 11 is incorporated
   herein by reference to the definitive Proxy Statement to be filed by the
   Company pursuant to Regulation 14A of the General Rules and Regulations
   under the Securities and Exchange Act of 1934 not later than April 29,
   1996.


   ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

               The information called for by this Item 12 is incorporated
   herein by reference to the definitive Proxy Statement to be filed by the
   Company pursuant to Regulation 14A of the General Rules and Regulations
   under the Securities and Exchange Act of 1934 not later than April 29,
   1996.



   ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

               The information called for by this Item 13 is incorporated
   herein by reference to the definitive Proxy Statement to be filed by the
   Company pursuant to Regulation 14A of the General Rules and Regulations
   under the Securities and Exchange Act of 1934 not later than April 29,
   1996.<PAGE>

<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 40 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 and Reorganization
                       by and among Registrant and Devon Energy Corporation, a
                       Delaware corporation, dated as of April 13, 1995
                       (incorporated by reference to Exhibit A to Registrant's
                       definitive Proxy Statement for its 1995 Annual Meeting
                       of Shareholders filed on April 21, 1995).

                       2.2 - Agreement and Plan of Merger by and among Devon
                       Energy Corporation, Devon Acquisition Corp. and Alta
                       Energy Corporation dated February 18, 1994
                       [incorporated by reference to Exhibit 2.1 to
                       Registrant's Registration Statement on Form S-4 (No.
                       33-76524)].

                       2.3 - Amendment to Agreement and Plan of Merger by and
                       among Devon Energy Corporation, Devon Acquisition Corp.
                       and Alta Energy Corporation dated April 13, 1994
                       [incorporated by reference to Exhibit 2.2 to Amendment
                       No. 1 to Registrant's Registration Statement on Form S-
                       4 (No. 33-76524)].

                       3.1 - Registrant's Certificate of Incorporation
                       (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 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).<PAGE>


                       4.3 - 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).

                       10.1 - Credit Agreement dated October 7, 1994, 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, 1994).

                       10.2 - First Amendment, dated January 27, 1995, to
                       Credit Agreement 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 10.2 to
                       Registrant's Annual Report on Form 10-K for the year
                       ended December 31, 1994).

                       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 - Severance Agreement between Devon Energy
                       Corporation (Nevada), Registrant 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).#

                       10.6 - Severance Agreement between Devon Energy
                       Corporation (Nevada), Registrant and Mr. H. R. Sanders,
                       Jr., dated December 3, 1992 (incorporated by reference
                       to Exhibit 10.11 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), Registrant 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), Registrant 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), Registrant 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), Registrant 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 - Stock Purchase Agreement dated January 14,
                       1994, between GSS Investments Corp. [a wholly-owned
                       subsidiary of Registrant] and Princor Growth Fund, Inc.
                       (incorporated by reference to Exhibit 3 to Amendment
                       No. 2 to Registrant's Schedule 13D dated as of January
                       7, 1994).

                       10.12 - Stock Purchase Agreement dated January 14,
                       1994, between Registrant and Andrew P. Carstensen, Jr.
                       (incorporated by reference to Exhibit 4 to Amendment
                       No. 2 to Registrant's Schedule 13D dated as of January
                       7, 1994).

                       10.13 - 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).

                       10.14 - 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).

                       10.15 - Purchase and Sale Agreement between Union Oil
                       Company of California and Devon Energy Corporation
                       (Nevada) (incorporated by reference to Exhibit 2 to
                       Registrant's Current Report on Form 8-K dated December
                       18, 1995)

                       11 - Computation of earnings per share

                       21 - Subsidiaries of Registrant (incorporated by
                       reference to Exhibit 21 to Registrant's Registration
                       Statement on Form 8-B filed on June 7, 1995).

                       23.1 - Consent of LaRoche & Associates

                       23.2 - Consent of KPMG Peat Marwick LLP

                       # Compensatory plans or arrangements.

         (b)   Reports on Form 8-K - A Current Report on Form 8-K dated
               December 18, 1995, was filed by the Registrant regarding the
               acquisition of certain Wyoming oil and natural gas properties
               and a gas processing plant for approximately $50.3 million.

<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 4, 1996            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 4, 1996            By   John W. Nichols                  
                                John W. Nichols
                                Chairman of the Board and Director


  March 4, 1996            By   J. Larry Nichols                 
                                J. Larry Nichols
                                President, Chief Executive Officer and Director


  March 4, 1996            By   H. R. Sanders, Jr.               
                                H. R. Sanders, Jr.
                                Executive Vice President and Director


  March 4, 1996            By   William T. Vaughn                
                                William T. Vaughn
                                Vice President - Finance


  March 4, 1996            By   Danny J. Heatly                  
                                Danny J. Heatly
                                Controller


  March 4, 1996            By   Thomas F. Ferguson               
                                Thomas F. Ferguson, Director



  March, 4 1996            By   David M. Gavrin                  
                                David M. Gavrin, Director



  March 4, 1996            By   Michael E. Gellert               
                                Michael E. Gellert, Director

<PAGE>