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, 1996
                               OR
      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                SECURITIES EXCHANGE ACT OF 1934
                 Commission File Number 1-10067

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

           Oklahoma                     73-1474008
(State or Other Jurisdiction of         (I.R.S. Employer
Incorporation or Organization)          Identification No.)

20 North Broadway, Suite 1500                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 shares        American Stock Exchange
                                   
Securities registered pursuant to Section 12(g) of the Act:  None

      Indicate by check mark whether the Registrant (1) has filed
all  reports required to be filed by Section 13 or 15(d)  of  the
Securities  Exchange Act of 1934 during the preceding  12  months
(or  for such shorter period that the Registrant was required  to
file  such  reports),  and (2) has been subject  to  such  filing
requirements for at least the past 90 days.
Yes   /x/     No

      Indicate  by check mark if disclosure of delinquent  filers
pursuant  to Item 405 of Regulation S-K is not contained  herein,
and will not be contained, to the best of Registrant's knowledge,
in  definitive  proxy or information statements  incorporated  by
reference in Part III of this Form 10-K or any amendment to  this
Form 10-K.  /x/

      The  aggregate  market value of the voting  stock  held  by
non-affiliates  of  the Registrant as of February  24,  1997  was
$1,020,619,000.  At such date 32,141,295 shares of  common  stock
were outstanding.

              DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 1997 annual meeting of stockholders -  Part III
<PAGE>

                       TABLE OF CONTENTS

                                                             Page

PART I
 Item 1. Business                                              3
 Item 2. Properties                                           12
 Item 3. Legal Proceedings                                    21
 Item 4. Submission of Matters to a Vote of Security Holders  22

PART II
 Item 5. Market for Registrant's Common Equity
          and Related Stockholder Matters                     22
 Item 6. Selected Financial Data                              24
 Item 7. Management's  Discussion and  Analysis
          of  Financial Condition and Results of Operations   26
 Item 8. Financial Statements and Supplementary Data          42
 Item 9. Changes  in  and Disagreements  with  Accountants
          on Accounting and Financial Disclosure              82

PART III
 Item 10. Directors and Executive Officers of
           the  Registrant                                    82
 Item 11. Executive Compensation                              82
 Item 12. Security Ownership of Certain Beneficial
           Owners  and Management                             82
 Item 13. Certain  Relationships  and
           Related  Transactions                              82

PART IV
 Item 14. Exhibits, Financial Statement Schedules,
           and Reports on Form 8-K                            83

                          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.  These
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."


                             PART I


ITEM 1.  BUSINESS

General

      Devon Energy Corporation ("Devon" or the "Company")  is  an
independent  energy  company engaged primarily  in  oil  and  gas
exploration,  development and production, and in the  acquisition
of  producing properties.  Through its predecessors, Devon  began
operations  in  1971.  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  currently owns interests in approximately 2,200  oil
and  gas  properties concentrated in five operating  areas:   the
Permian  Basin in southeastern New Mexico and western Texas;  the
San  Juan  Basin  in northwestern New Mexico; the Rocky  Mountain
region  in Wyoming; the Mid-continent region in Oklahoma and  the
Texas  Panhandle;  and  the Western Canada Sedimentary  Basin  in
Alberta,  Canada.  (A  detailed description  of  the  significant
properties  can be found under "Item 2. Properties -  Significant
Properties" beginning on page 16 hereof.)

     At December 31, 1996, Devon's estimated proved reserves were
179.3  MMBoe, which were balanced between oil and NGLs (45%)  and
natural  gas  (55%).   The present value of  pre-tax  future  net
revenues discounted at 10% per annum assuming unescalated  prices
("10%  Present Value") of such reserves was $1.6 billion.   Devon
is  one of the top 20 public independent oil and gas companies in
the United States, as measured by oil and gas reserves.

Strategy

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

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

      In  the  last  five years alone, Devon has consummated  six
significant acquisitions and drilled 637 new wells, 614 of  which
were   producers.  These  activities  have  resulted  in  reserve
additions  of  196.9  million Boe.   Capital  costs  incurred  to
complete these activities totaled $743.2 million, for a five-year
finding and development cost of $3.77 per Boe.  Reserve additions
and adjustments, minus production and property sales, resulted in
an annual average reserve replacement factor of 435%.

      Devon's objective, however, is to increase value per share,
not  simply  to increase total assets.  Reserves have grown  from
3.12  Boe  per fully-diluted share at year-end 1991 to 4.84   Boe
per fully-diluted share at year-end 1996.  During this same five-
year period, net debt (long-term debt minus working capital)  has
remained relatively low, never exceeding $1.17 per Boe,  and  was
zero at year-end 1996.

      The  oil  and  gas  industry is characterized  by  volatile
product  prices.  Devon's management believes that by (a) keeping
debt  levels low, (b) concentrating its properties in core  areas
to  achieve economies of scale, (c) acquiring and developing high
profit  margin properties,  (d) continually disposing of marginal
and  non-strategic properties and (e) balancing reserves  between
oil and gas, Devon's profitability will be maximized, even during
periods of low oil and/or gas prices.  In addition, Devon remains
financially  flexible  to  take advantage  of  opportunities  for
mergers, acquisitions, exploration or other growth opportunities.

Recent Developments

      During 1996 Devon completed two notable transactions  which
had  a  significantly positive impact on the Company's  size  and
financial strength.  These two transactions are discussed below.

      Trust  Convertible Preferred Offering.  On  July  3,  1996,
Devon  Financing  Trust, a Delaware business trust  organized  by
Devon,  closed a $149.5 million private placement  of  6-1/2% trust
convertible preferred securities (the "TCP Securities").  The net
proceeds  of $144.7 million were used to repay substantially  all
of  Devon's  then  outstanding bank debt. This increased  Devon's
unused   borrowing  capacity,  which  can  be  used  for   future
acquisitions and drilling projects.

      The  TCP Securities, which do not mature until June,  2026,
are convertible at the holders' option into Devon common stock at
a  conversion  price of $30.50 per common share.  The  securities
are redeemable at Devon's option beginning on June 18, 1999.  See
note  9  to  Devon's  consolidated financial statements  included
herein for a detailed description of the TCP Securities.

       Kerr-McGee  Transaction.   On  December  31,  1996,  Devon
acquired  the North American onshore oil and gas exploration  and
production properties and business of Kerr-McGee Corporation (the
"KMG-NAOS Properties") in exchange for 9,954,000 shares of  Devon
common  stock  (the "Kerr-McGee Transaction").   The  transaction
increased  Devon's  year-end  1996  reserves  by  62  MMBoe,   or
approximately  50%,  and  tripled the Company's  net  undeveloped
leasehold   inventory  to  490,000  net  acres.    The   KMG-NAOS
Properties  are  concentrated in the  Permian  Basin,  the  Rocky
Mountains  and the Mid-Continent regions of the United  States  -
areas in which Devon previously owned significant reserves -  and
in the Western Canada Sedimentary Basin of Alberta, Canada, which
is a new producing province for Devon.

     After consummation of the Kerr-McGee Transaction, Kerr-McGee
Corporation  ("Kerr-McGee")  owns 31%  (26%  on  a  fully-diluted
basis)  of  Devon's outstanding common stock.  Because  of  Kerr-
McGee's relatively large ownership position, Devon and Kerr-McGee
entered  into  two  agreements  which  define  and  limit   their
respective rights and obligations. In addition, Devon's board  of
directors  amended  Devon's share rights  plan  so  that  Devon's
existing  anti-takeover defenses will remain in force  for  third
parties  and/or  certain  further transactions  with  Kerr-McGee.
Each  of  these arrangements are defined in the Stock Rights  and
Restrictions  Agreement, the Registration Rights  Agreement,  the
First  Amendment to the Rights Agreement and the Second Amendment
to  the  Rights  Agreement.   These  documents  are  included  as
exhibits to this Form 10-K.

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 1997 will be concentrated in the  Permian
Basin, Rocky Mountains and Gulf Coast regions of the U.S. and  in
the Western Canada Sedimentary Basin of Alberta, Canada.

      The following tables set forth Devon's drilling results for
the past five years.
<TABLE>
<CAPTION>

                      Development Wells
               Gross (1)              Net (2)
         ----------------------   ----------------------
         Productive  Dry  Total   Productive  Dry   Total
         ----------  ---  -----   ----------  ---   -----
<S>        <C>      <C>   <C>     <C>        <C>   <C>
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
1996       188       3    191     137.05     0.95  138.00
           ---      --    ---     ------     ----  ------
           594      13    607     376.55     3.04  379.59
</TABLE>
<TABLE>
<CAPTION>
                      Exploratory Wells
               Gross (1)              Net (2)
         ----------------------   ----------------------
         Productive  Dry  Total   Productive  Dry   Total
         ----------  ---  -----   ----------  ---   -----
<S>         <C>      <C>   <C>      <C>      <C>    <C>
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
1996         2        1     3       1.50     0.08    1.58
            --       --    --       ----     ----    ----
            20       10    30       7.69     4.37   12.06


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

      As  of  December 31, 1996, Devon was participating  in  the
drilling of 30 gross (14.51 net) wells which are not included  in
the  table above. Through February 24, 1997, six gross (1.30 net)
of  these  wells were completed as productive and  the  remaining
wells were still in progress.

Customers

      For  the  year  ended  December 31, 1996,  one  significant
purchaser,   Aquila  Energy  Marketing  Corporation   ("Aquila"),
accounted  for 45% of Devon's natural gas sales.   For  the  year
ended  December 31, 1995, two significant purchasers, Aquila  and
Enron  Gas Marketing, Inc. ("Enron"), accounted for 31% and  16%,
respectively, of Devon's gas sales.  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. Until September, 1995, MOTI was a significant purchaser of
Devon's coal seam gas production at market-sensitive prices under
the  terms  of  a five-year contract entered into in  May,  1990.
Aquila and Enron purchase gas from numerous Devon properties,  at
variable  and market-sensitive prices.   Devon does not  consider
itself  dependent upon any one of these purchasers,  since  other
purchasers  are willing to purchase this same gas  production  at
competitive prices.

      Devon  sells its remaining gas production to a  variety  of
customers  including pipelines, utilities, gas  marketing  firms,
industrial  users  and  local  distribution  companies.  Existing
gathering  systems  and interstate and intrastate  pipelines  are
used to consummate gas sales and deliveries.

     The principal customers for Devon's crude oil production are
refiners,  remarketers and other companies, some  of  which  have
pipeline  facilities near the producing properties. In the  event
pipeline facilities are not conveniently available, crude oil  is
trucked or barged to storage, refining or pipeline facilities.

Oil and Natural Gas Marketing

      Oil  Marketing.  Devon's oil production is sold under  both
long-  and short-term agreements at prices negotiated between the
parties.

     Natural Gas Marketing.  Virtually all of Devon's natural gas
production  is  sold  at  variable, or  market-sensitive  prices.
Though  exact percentages vary daily, approximately  7%  of  such
natural gas is sold under short-term contracts. The remaining 93%
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.

Competition

      The  oil  and  gas  business is highly  competitive.  Devon
encounters  competition by major integrated and  independent  oil
and gas companies in acquiring drilling prospects and properties,
contracting   for   drilling  equipment  and   securing   trained
personnel.  Intense competition occurs with respect to marketing,
particularly  of natural gas. Certain competitors have  resources
which substantially exceed those of Devon.

Seasonal Nature of Business

      Generally,  but  not  always, the demand  for  natural  gas
decreases  during  the  summer months and  increases  during  the
winter  months. Seasonal anomalies such as mild winters sometimes
lessen this fluctuation. In addition, pipelines, utilities, local
distribution  companies and industrial users have begun  to  more
effectively utilize natural gas storage facilities by  purchasing
some of their anticipated winter requirements during the summer.

Government Regulation

       Devon's  operations  are  subject  to  various  levels  of
government  controls  and regulations in the  United  States  and
Canada.

     United States Regulation

      In the United States, legislation affecting the oil and gas
industry  has  been  pervasive and is under constant  review  for
amendment  or  expansion. Pursuant to such legislation,  numerous
federal,  state  and local departments and agencies  have  issued
extensive  rules  and regulations binding  on  the  oil  and  gas
industry  and  its  individual  members,  some  of  which   carry
substantial  penalties for the failure to comply. Such  laws  and
regulations have a significant impact on oil and gas drilling and
production  activities, increase the cost of doing business  and,
consequently,  affect profitability. Inasmuch as new  legislation
affecting  the oil and gas industry is commonplace  and  existing
laws  and  regulations are frequently amended  or  reinterpreted,
Devon is unable to predict the future cost or impact of complying
with such laws and regulations.

       Exploration   and  Production.   Devon's   United   States
operations  are  subject to various types of  regulation  at  the
federal,   state  and  local  levels.  Such  regulation  includes
requiring permits for the drilling of wells; maintaining  bonding
requirements  in order to drill or operate wells; submitting  and
implementing  spill  prevention  plans;  submitting  notification
relating to the presence, use and release of certain contaminants
incidental to oil and gas operations; and regulating the location
of  wells,  the  method of drilling and casing  wells,  the  use,
transportation, storage and disposal of fluids and materials used
in  connection  with drilling and production activities,  surface
usage  and  the restoration of properties upon which  wells  have
been  drilled,  the  plugging and abandoning of  wells,  and  the
transporting  of production. Devon's operations are also  subject
to  various conservation matters, including the regulation of the
size of drilling and spacing units or proration units, the number
of  wells which may be drilled in a unit, and the unitization  or
pooling  of  oil and gas properties. In this regard, some  states
allow  the  forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of lands
and  leases, which may make it more difficult to develop oil  and
gas  properties. In addition, state conservation  laws  establish
maximum  rates  of  production from oil and gas wells,  generally
prohibit  the  venting  or  flaring of gas,  and  impose  certain
requirements  regarding the ratable purchase of  production.  The
effect  of these regulations is to limit the amounts of  oil  and
gas  Devon can produce from its wells and to limit the number  of
wells or the locations at which Devon can drill.

     Certain of Devon's oil and gas leases, including most of its
leases in the San Juan Basin and many of the Company's leases  in
southeast  New  Mexico and Wyoming, are granted  by  the  federal
government  and  administered by various federal  agencies.  Such
leases  require compliance with detailed federal regulations  and
orders   which  regulate,  among  other  matters,  drilling   and
operations on lands covered by these leases, and calculation  and
disbursement  of royalty payments to the federal government.  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  harmful
substances.  However, 100% coverage is not maintained  concerning
any  environmental  claim,  and no coverage  is  maintained  with
respect  to  any award of punitive damages against Devon  or  any
penalty  or  fine  required to be paid by Devon  because  of  its
violation   of   any  federal,  state  or  local   law.   Devon's
unreimbursed  expenditures in 1996 concerning such  matters  were
immaterial,  but Devon cannot predict with any reasonable  degree
of certainty its future exposure concerning such matters.

      Devon  is  also subject to laws and regulations  concerning
occupational safety and health. Due to the continued  changes  in
these  laws  and  regulations, and the judicial  construction  of
same,  Devon is unable to predict with any reasonable  degree  of
certainty  its  future costs of complying  with  these  laws  and
regulations.

      In  1992  Devon  retained the services  of  an  independent
environmental   engineering  firm  to  provide  a   comprehensive
evaluation  of  Devon's significant properties and  to  otherwise
advise Devon concerning its compliance with various environmental
laws.  In  1993  Devon established its own internal Environmental
Industrial  Hygiene  and  Safety  Department  to  perform   these
functions.  This  department is responsible for  instituting  and
maintaining  an environmental and safety compliance  program  for
Devon.  The program includes field inspections of properties  and
internal audits of Devon's compliance procedures.

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

     Canadian Regulation

     Canadian Government Regulation.  The oil and gas industry is
subject  to extensive controls and regulations imposed by various
levels  of  government.  It is not expected  that  any  of  these
controls  or regulations will affect Devon's Canadian  operations
in a manner materially different than they would affect other oil
and gas companies of similar size.

      The  North  American Free Trade Agreement.  On  January  1,
1994, the North American Free Trade Agreement ("NAFTA") among the
governments of Canada, the U.S. and Mexico became effective.  The
NAFTA carries forward most of the material energy terms contained
in the Canada-U.S. Free Trade Agreement. In the context of energy
resources,  Canada continues to remain free to determine  whether
exports  to the U.S. or Mexico will be allowed provided that  any
export  restrictions do not: (i) reduce the proportion of  energy
resource exported relative to domestic use, (ii) impose an export
price  higher  than the domestic price, and (iii) disrupt  normal
channels  of  supply.  All three countries  are  prohibited  from
imposing minimum export or import price requirements.

      The NAFTA contemplates the reduction of Mexican restrictive
trade practices in the energy sector and prohibits discriminatory
border   restrictions  and  export  taxes.  The  agreement   also
contemplates  clearer disciplines on regulators  to  ensure  fair
implementation  of  any  regulatory  changes  and   to   minimize
disruption  of  contractual arrangements, which is important  for
Canadian natural gas exports.

       Royalties   and  Incentives.   In  addition   to   federal
regulation,   each   producing  province  has   legislation   and
regulations  which  govern  land  tenure,  royalties,  production
rates,  environmental protection and other matters.  The  royalty
regime  is a significant factor in the profitability of  oil  and
natural  gas  production. Royalties payable  on  production  from
lands  other  than  Crown  lands are determined  by  negotiations
between  the  mineral owner and the lessee. Crown  royalties  are
determined  by government regulation and are generally calculated
as  a  percentage of the value of the gross production,  and  the
rate of royalties payable generally depends in part on prescribed
reference prices, well productivity, geographical location, field
discovery  date and the type of quality of the petroleum  product
produced.

      From  time  to time the governments of Canada, Alberta  and
British  Columbia have established incentive programs which  have
included  royalty  rate  reductions,  royalty  holidays  and  tax
credits  for  the  purpose of encouraging  oil  and  natural  gas
exploration  or  enhanced  recovery  projects.  Regulations  made
pursuant  to  the  Alberta Mines and Mineral Act provide  various
incentives for exploring and developing oil reserves in Alberta.

      In Alberta, the royalty reserved to the Crown in respect of
natural gas production, subject to various incentives, is between
15% and 30%, in the case of new gas, and between 15% and 35%,  in
the  case  of  old gas, depending upon a prescribed or  corporate
average  reference price. Gas produced from qualifying  intervals
in  eligible gas wells spudded or deepened to a depth below 2,500
meters  is  subject to a royalty exemption, the amount  of  which
depends on the depth of the well.

      In Alberta, a producer of oil or natural gas is entitled to
a  credit against the royalties payable to the Crown by virtue of
the Alberta Royalty Tax Credit ("ARTC") program. The ARTC program
is  based on a price sensitive formula, and the ARTC rate  varies
between  75%, at prices for oil below $100 per cubic  meter,  and
25%,  at  prices  above $210 per cubic meter. The  ARTC  rate  is
applied  to  a  maximum of $2,000,000 of Alberta Crown  royalties
payable for each producer or associated group of producers. Crown
royalties  on production from producing properties acquired  from
corporations claiming maximum entitlement to ARTC will  generally
not be eligible for ARTC. The rate is established quarterly based
on  the  average  "par  price",  as  determined  by  the  Alberta
Department of Energy for the previous quarterly period.

      Oil  and  natural gas royalty holidays and  reductions  for
specific wells reduce the amount of Crown royalties paid by Devon
to the provincial governments. The ARTC program provides a rebate
on   Crown  royalties  paid  in  respect  of  eligible  producing
properties. Both of these incentives increase the net  income  of
Devon.

      Producers  of oil and natural gas in British  Columbia  are
required to pay annual rental payments in respect of Crown leases
and royalties and freehold production taxes in respect of oil and
gas  produced  from  Crown and freehold lands  respectively.  The
amount  payable  as a royalty in respect of oil  depends  on  the
vintage  of  the  oil  (whether  it  was  produced  from  a  pool
discovered before or after October 31, 1975), the quantity of oil
produced  in a month and the value of the oil. Oil produced  from
newly  discovered  pools may be exempt  from  the  payment  of  a
royalty  for  the  first  36 months of  production.  The  royalty
payable on natural gas is determined by a sliding scale based  on
a  reference price which is the greater of the amount obtained by
the  producer  and at prescribed minimum price. Gas  produced  in
association  with  oil  has a minimum royalty  of  8%  while  the
royalty in respect of other gas may not be less than 15%.

      Canadian Environmental Regulation.  The oil and natural gas
industry   is  currently  subject  to  environmental   regulation
pursuant  to  provincial  and federal legislation.  Environmental
legislation   provides  for  restrictions  and  prohibitions   on
releases  or emissions of various substances produced or utilized
in  association with certain oil and gas industry operations.  In
addition,  legislation requires that well and facility  sites  be
abandoned   and  reclaimed  to  the  satisfaction  of  provincial
authorities.  A  breach of such legislation  may  result  in  the
imposition  of  fines  and penalties. In  Alberta,  environmental
compliance has been governed by the Environmental Protection  and
Enhancement Act (Alberta) (the "EPEA") since September  1,  1993.
In  addition  to  replacing a variety  of  older  statutes  which
related  to environmental matters, the EPEA also imposes  certain
new   environmental  responsibilities  on  oil  and  natural  gas
operators  in  Alberta  and  in certain  instances  also  imposes
greater  penalties for violations. Devon is committed to  meeting
its  responsibilities  to  protect the  environment  wherever  it
operates and anticipates making increased, although not material,
expenditures of both a capital and expense nature as a result  of
the increasingly stringent laws relating to the protection of the
environment.

      Natural  Gas  Regulations.  Natural  gas  sold  within  the
Province  of  Alberta  is not subject to regulation.  Prices  are
negotiated   and   established  based  upon   prevailing   market
conditions. Natural gas sold outside Alberta can only be  removed
from  the  province  under  a  removal  permit,  issued  by   the
Government of Alberta. The Government, through the Alberta Energy
and  Utilities Board ("AEUB"), will issue a removal  permit  only
after  assessing the reserves from the proposed pools  supporting
the  application,  and to a lesser extent reviewing  the  pricing
provisions of the sales contract.

      Natural  gas  exported to the United States is  subject  to
approval  by  the  National Energy Board  of  the  Government  of
Canada. Exports can be approved provided that the National Energy
Board  is satisfied that Canadian demand will be met from current
and  expected supplies and the sale is of net benefit to  Canada.
While  export  prices are determined by negotiation  between  the
buyer and seller, the National Energy Board monitors the prices.

      Investment Canada Act.  The Investment Canada Act  requires
Government  of  Canada  approval,  in  certain  cases,   of   the
acquisition  of control of a Canadian business by an entity  that
is  not  controlled  by Canadians. In certain circumstances,  the
acquisition  of natural resource properties may be considered  to
be a transaction that constitutes an acquisition of control of  a
Canadian  business requiring Government of Canada  approval.  The
Act  requires notification of the establishment of new  unrelated
businesses in Canada by entities not controlled by Canadians, but
does  not  require Government of Canada approval except when  the
new business is related to Canada's cultural heritage or national
identity.

Employees

     As of December 31, 1996, Devon's staff consisted of 231 full-
time  employees, including 19 professionals in engineering, 8  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.   The  Company  also   engages   independent
consulting   petroleum  engineers,  environmental  professionals,
geologists, geophysicists, landmen and attorneys on a fee  basis.
Devon  expects  to  add between 100 and 125  full-time  employees
during  1997  as  a  result of the Kerr-McGee Transaction.   (See
"Management's Discussion and Analysis of Financial Condition  and
Results   of   Operations  -  1997  Estimates   -   General   and
Administrative Expenses".)

ITEM 2.  PROPERTIES

     Substantially all of Devon's properties consist of interests
in  developed  and  undeveloped oil and gas  leases  and  mineral
acreage  located  in  New Mexico, Wyoming,  Texas,  Oklahoma  and
Alberta, Canada. These interests entitle Devon to drill  for  and
produce  oil,  natural gas and NGLs from specific areas.  Devon's
interests  are  mostly  in  the form  of  working  interests  and
production payments, and, to a lesser extent, overriding royalty,
royalty,  mineral and net profits interests and  other  forms  of
direct and indirect ownership in oil and gas properties.

Proved Reserves and Estimated Future Net Revenue

      "Proved Reserves" are those quantities of oil, natural  gas
and  NGLs which geological and engineering data demonstrate  with
reasonable  certainty to be recoverable in the future from  known
reservoirs  under  existing  economic and  operating  conditions.
Estimates  of  proved reserves are strictly technical  judgments,
and are not knowingly influenced by attitudes of conservatism  or
optimism. The following table sets forth Devon's estimated proved
reserves, the estimated future net revenues therefrom and the 10%
Present Value thereof as of December 31, 1996. Approximately  94%
of  Devon's  domestic proved reserves were estimated  by  LaRoche
Petroleum  Consultants,  Ltd.,  independent  petroleum  engineers
("LaRoche").  The  remainder of such reserves were  estimated  by
Devon's  internal staff of engineers. All of the Canadian  proved
reserves   were   calculated   by   the   independent   petroleum
consultants,   AMH  Group  Ltd.  ("AMH").   In  preparing   their
estimates,   LaRoche,  AMH  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 14 to Devon's consolidated financial
statements  included  herein, except that  federal  income  taxes
attributable to such future net revenues have been disregarded in
the presentation below.
<TABLE>
<CAPTION>
                                      Total       Proved   Proved
                                     Proved    Developed   Undeveloped
                                   Reserves  Reserves (1)  Reserves (2)
     <S>                            <C>        <C>        <C>
     Oil (MBBls)                      67,481      60,202    7,279
     Gas (MMcf)                       595,519    570,265   25,254
     NGLs (MBoe)                      12,579      11,212    1,367
     MBoe (3)                         179,313    166,457   12,856
     Pre-tax Future Net Revenue
      ($ thousands)(4)              2,863,536  2,677,459  186,077
     Pre-tax 10% Present Value
      ($ thousands)(4)              1,621,992  1,532,021   89,971


(1)  Proved  developed  reserves  are  proved  reserves  that   are
     expected  to  be  recovered from existing wells  with  existing
     equipment and operating methods.

(2)  Proved  undeveloped  reserves  are  proved  reserves   to   be
     recovered from new wells on undrilled acreage or from  existing
     wells  where  a  relatively major expenditure is  required  for
     recompletion, deepening or new fluid injection facilities.

(3)  Gas reserves are converted to MBoe at the rate of six MMcf per
     MBbl  of  oil,  based  upon  the  approximate  relative  energy
     content  of  natural gas to oil, which rate is not  necessarily
     indicative  of  the  relationship of gas  to  oil  prices.  The
     respective  prices  of  gas  and oil  are  affected  by  market
     conditions  and  other factors in addition to  relative  energy
     content.

(4)  Estimated  future net revenue represents  estimated  future
     gross  revenue  to be generated from the production  of  proved
     reserves,  net  of estimated production and 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, 1996. 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 $24.52 per Bbl of  oil,
     $3.35  per  Mcf  of  natural gas ($3.43 per Mcf  including  the
     effect  of the San Juan Basin Transaction), and $23.34 per  Boe
     of  NGLs.  These prices compare to benchmark prices  of  $24.25
     for  West Texas Intermediate crude oil and $3.67 for Texas Gulf
     Coast spot gas.
</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, 1996. There can be no assurance that all of  the
proved  reserves  will be produced and sold  within  the  periods
indicated,  that  the  assumed prices will be  realized  or  that
existing contracts will be honored or judicially enforced.

      The  process  of  estimating oil, gas and NGL  reserves  is
complex,  requiring  significant  subjective  decisions  in   the
evaluation of available geological, engineering and economic data
for  each  reservoir. The data for a given reservoir  may  change
substantially  over  time  as a result of,  among  other  things,
additional development activity, production history and viability
of  production  under varying economic conditions;  consequently,
material revisions to existing reserve estimates may occur in the
future.

      The  following table presents the net quantities of Devon's
oil,  natural  gas and NGL reserves as of the end  of  the  years
indicated.   Approximately 88%, 95%, 91%, 92% and 94% of  Devon's
domestic reserves as of the years ended December 31, 1992,  1993,
1994,  1995  and 1996, respectively, were estimated  by  LaRoche.
The  balance of the domestic reserves were estimated  by  Devon's
internal  staff of engineers.  All of the 1996 Canadian  reserves
were calculated by AMH.
<TABLE>
<CAPTION>

                    Total Proved Reserves       Proved Developed Reserves
             -------------------------------  -------------------------------
As of        Oil(MBbls) Gas(MMcf) NGLs(MBoe)  Oil(MBbls) Gas(MMcf) NGLs(MBoe)
December 31, ---------- --------  ----------  ---------- --------- ----------
<S>           <C>        <C>         <C>         <C>      <C>        <C>
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
1996          67,481     595,519     12,579      60,202   570,265    11,212
</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, 1996, is set forth in "Item
6. Selected Financial Data."

Well Statistics

      As  of  December  31, 1996, Devon had interests  in  13,992
producing wells, of which 10,839 gross (1,311 net) were oil wells
and 3,153 gross (760 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.

Undeveloped Acreage

      The  following  table  sets  forth  Devon's  developed  and
undeveloped oil and gas lease and mineral acreage as of  December
31, 1996.
<TABLE>
<CAPTION>

                             Developed         Undeveloped
                       -------------------   ------------------
                       Gross(1)     Net(2)   Gross(1)    Net(2)
                       --------     ------   --------    ------
    <S>               <C>          <C>     <C>         <C>
    Alabama               6,166      2,608       400        78
    Arkansas              9,091      1,830    12,184     2,517
    Colorado              6,588      3,065    22,368     9,568
    Kansas               20,676      8,912     6,160       581
    Louisiana            14,981      5,373    14,663     6,990
    Mississippi           9,224        575       825       222
    Montana              16,486        445    11,891     1,779
    Nebraska                160         80     6,517     1,377
    New Mexico          157,075     68,882   218,135    69,554
    North Dakota         17,157      6,030     6,982       755
    Oklahoma            294,069     88,904   190,461    38,356
    South Dakota          5,771        152       322       238
    Texas               839,851    227,654   600,725   176,096
    Utah                  5,305        864       600       600
    Wyoming             253,146    103,967   160,001   106,432
                     ----------  ---------   -------   ------- 
    Total U. S.       1,655,746    519,341 1,252,234   415,143
    Canada              187,277     75,637   118,808    75,262
                     ----------    ------- ---------   -------
    Grand Total       1,843,023    594,978 1,371,042   490,405
                      =========    ======= =========   =======

(1)   Gross acres are the total number of acres  in  which
      Devon owns a working interest.
(2)   Net  refers  to  gross acres multiplied  by  Devon's
      fractional working interests therein.
</TABLE>

Operation of Properties

      The day-to-day operations of oil and gas properties is  the
responsibility  of  an  operator  designated  under  pooling   or
operating   agreements.   The  operator  supervises   production,
maintains   production  records,  employs  field  personnel   and
performs other functions.  The charges under operating agreements
customarily  vary with the depth and location of the  well  being
operated.

      Devon  is  the operator of 2,006 of its 13,992  wells.   As
operator,  Devon  receives  reimbursement  for  direct   expenses
incurred in the performance of its duties as well as monthly per-
well  producing  and  drilling overhead  reimbursement  at  rates
customarily  charged  in  the area to or  by  unaffiliated  third
parties.   In  presenting its financial data, Devon  records  the
monthly  overhead reimbursements as a reduction  of  general  and
administrative expense, which is a common industry practice.

Significant Properties

      The  following  table sets forth information  on  the  most
significant  geographic  areas in which  Devon's  properties  are
located as of December 31, 1996.
<TABLE>
<CAPTION>

                                                            10% Present
                                                              Value(3)
               Oil(MBbls) Gas(MMcf) NGLs(MBoe) MBoe(1) MBoe%(2) ($000) Value%(4)
               ---------- --------- ---------- ------- -------- ------ ---------
<S>               <C>     <C>       <C>       <C>     <C>    <C>         <C>
Permian Basin:
West Texas and
Southeast New Mexico
  Grayburg-Jackson
  Field           22,007    7,983     1,955    25,293  14.1%   $193,637 12.0%
  Ozona Field        254   64,774     1,725    12,775   7.1%    102,385  6.3%
  Other           24,296   80,302     3,128    40,808  22.8%    366,870 22.6%
                  ------   ------     -----    ------  -----   -------- -----
  Total           46,557  153,059     6,808    78,876  44.0%   $662,892 40.9%

Rocky Mountains:
Colorado and Wyoming
  Worland Unit     1,966   56,138     3,797    15,119   8.4%   $133,571  8.2%
  Other            8,516   49,333       460    17,198   9.6%    169,133 10.5%
                  ------   ------     -----    ------  -----   -------- -----
  Total           10,482  105,471     4,257    32,317  18.0%   $302,704 18.7%

San Juan Basin:
Northwest New Mexico
  Northeast Blanco
  Unit                 4  108,789       47     18,183  10.1%  $180,724(5) 11.1%
  32-9 Unit            0   53,727        0      8,955   5.0%    94,384(6)  5.8%
  Other                3      511       16        104   0.1%     1,235     0.1%
                      --  -------      ---     ------  -----  --------    -----
  Total                7  163,027       63     27,242  15.2%  $276,343    17.0%

Mid-Continent:
Oklahoma and
Texas Panhandle    1,982  127,752      538     23,812  13.3%  $224,326    13.8%

Canada             7,530   40,858      884     15,223   8.5%  $135,389(7)  8.3%

All Other 
Properties           923    5,352       29      1,843   1.0%    20,338     1.3%
                   -----   ------     ----     ------  -----  --------     ----
Grand Total       67,481  595,519   12,579    179,313 100.0% $1,621,992  100.0%
                  ======  =======   ======    ======= ====== ==========  ======


(1)   Gas reserves are converted to MBoe at the rate of six  MMcf
  of  gas  per  MBbl of oil, based upon the approximate  relative
  energy  content  of  natural gas to  oil,  which  rate  is  not
  necessarily  indicative  of  the relationship  of  gas  to  oil
  prices.  The  respective prices of gas and oil are affected  by
  market  and  other  factors  in  addition  to  relative  energy
  content.
(2)  Percentage which MBoe for the basin or region bears to total
  MBoe for all Proved Reserves.
(3)  Determined in accordance with SEC guidelines, except that no
  effect is given to future income taxes.
(4)  Percentage which present value for the basin or region bears
  to total present value for all Proved Reserves.
(5)   Includes $24.4 million of additional value attributable  to
  the San Juan Basin Transaction through the year 2002.
(6)   Includes $14.3 million of additional value attributable  to
  the San Juan Basin Transaction through the year 2002.
(7)   Canadian dollars converted to U. S. dollars at the rate  of
  $1 Canadian : $0.7297 U. S.
</TABLE>

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

      Grayburg-Jackson Field. Devon acquired the Grayburg-Jackson
Field in 1994. The property consists of approximately 8,500 acres
located  in  the southeastern New Mexico portion of  the  Permian
Basin. The field produces from an 800-foot thick interval of  the
Grayburg  and San Andres Formations at depths between  3,000  and
4,000 feet. The Grayburg-Jackson Field contains approximately one-
third  of  Devon's  proved oil reserves and  is  Devon's  largest
Permian Basin property.

     Production in this field was established in the 1930's, with
most  of  the  current producing wells drilled since  1970.  When
Devon acquired this property in 1994, drilling by previous owners
had developed the property on an average spacing of over 40 acres
per  well.  Additional oil reserves were recovered  from  similar
properties  in the immediate vicinity by infill drilling  to  20-
acre  per  well spacing and subsequent waterflooding. Based  upon
analogy  to  these  properties, Devon  initiated  a  $65  million
capital   development  project  in  1994.  The  project  includes
drilling  approximately  150  infill wells,  converting  selected
producing  wells  to  water injection wells  and  optimizing  the
existing  waterflood.  Devon substantially completed  the  infill
drilling phase of the project in July, 1996. The majority of  the
field should be in the initial phases of full water injection  by
mid-1997.  Completion  of  the  waterflood  facilities  over  the
remainder of the field will require the additional conversion  of
more than 90 producing wells to injection wells, construction  of
a  second water injection plant and installation of an additional
40 miles of injection pipeline.

      At  year-end 1996, production averaged approximately  3,000
Boe per day. Devon anticipates that continued water injection and
completion of the waterflood facilities will further improve  oil
and gas recoveries.

      Ozona  Field. The Ozona Field encompasses more than 200,000
acres in Crockett County, Texas, situated 120 miles southeast  of
Midland,  Texas. The field produces gas from the Canyon Formation
at depths of 6,000 to 9,000 feet. The field has been developed on
80-acre  spacing, with portions now being infill drilled  to  40-
acre  spacing.  Through year-end 1996, Devon  drilled  34  Canyon
wells. Additional significant producing wells and acreage were
obtained in the Kerr-McGee Transaction.  

      Devon has no Canyon locations currently identified for 1997
drilling.  However,  it  is  anticipated  that  undrilled  Canyon
locations will be found on the acreage acquired by Devon in 1996.

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

     Worland Property. The property lies on a 25,000-acre federal
unit  in  Big  Horn and Washakie Counties, Wyoming. In  December,
1995,  Devon  purchased a significant interest in  producing  and
undeveloped  acreage and a natural gas processing plant  on  this
property. In early 1996, Devon increased its working interest  to
98%  in  the developed leases through several small acquisitions.
These  acquisitions also increased Devon's interest  in  the  gas
processing plant to 100% and in the undeveloped oil and gas lease
acreage  to  approximately 99%. These acquired  assets,  combined
with  the  small  interest  Devon  previously  owned,  had  total
estimated proved reserves of 15.1 MMBoe as of year-end 1996.

      The Worland property is located in the Big Horn Basin,  and
contains  three  separate fields situated along a major  geologic
feature  referred  to  as  a  draped  anticline.  Seven  separate
horizons  have  proven  productive on  the  property.  The  Muddy
Formation and the First, Second, Third and Fourth Members of  the
Frontier Formation produce sweet gas from sandstone reservoirs at
depths   ranging  from  7,100  to  9,000  feet.  The   underlying
Phosphoria  Formation  produces oil and sour  gas  from  dolomite
reservoirs  encountered at a depth of approximately 10,000  feet.
The  Tensleep  Formation, the deepest proven reservoir,  produces
oil from sandstone at a depth of approximately 10,500 feet.

      Initial  oil  and  sour gas production was  established  at
Worland  in the 1940's from the Phosphoria Formation.  Sweet  gas
production  from the overlying Frontier and Muddy reservoirs  was
established   in   the  1960's.  Tensleep  oil   production   was
established in the 1970's.

       Devon  believes  that  the  property  contains  additional
exploitation   opportunities  for  all  the  proven   reservoirs.
Consequently, a drilling program and a 3-D seismic  program  have
been initiated to further develop the established reservoirs  and
to  extend  and  define their productive limits. Devon  also  has
begun  a  program  to  apply  modern completion  and  stimulation
techniques to selected existing wells. Additionally, Devon  plans
to  upgrade the existing gas processing plant from 15 MMcf of gas
per day to 20 MMcf per day during the first quarter of 1997.

      San Juan Basin.  Devon's single largest natural gas reserve
position  relates to its interests in two federal  units  in  the
northwest  New Mexico portion of the San Juan Basin:  the  33,000
acre  NEBU,  in Rio Arriba and San Juan Counties, and the  22,400
acre  32-9 Unit in San Juan County. The San Juan Basin, a densely
drilled   area  covering  3,700  square  miles  in  central   and
northwestern  New  Mexico, has 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 104.1 Bcf, of
Devon's proved reserves attributable to NEBU are associated  with
the  Fruitland  coal formation. The potential for gas  production
from  coal seams varies depending upon the thickness of the  coal
formation,  the type of coal in place, the depth at which  it  is
found and other factors.  NEBU is located in the central part  of
the  San  Juan Basin where each of the factors is at or near  its
optimum.  NEBU is operated by Devon. The Company initially  began
developing   its  coal  seam  interest  during  1988,  eventually
drilling  102  wells  -  the  maximum  permitted  under  existing
320-acre spacing on NEBU's 33,000 acres.

     The current reserve estimates at NEBU assume that 55% to 65%
of  the  coal  seam  gas  in place can be economically  recovered
through existing wells. In the near term, Devon is implementing a
project  which may increase production and recoverable  reserves.
This  "line looping" project involves laying additional gathering
lines  and installing compressors to decrease operating pressure.
It was begun in mid-1996 and should be substantially completed by
late  1997. Initial results from the work completed in 1996  were
favorable,  and  year-end 1996 reserve estimates  were  increased
slightly   (approximately  2.6  Bcf)  to  reflect  this  outcome.
Approximately  $2.3 million is expected to be spent  in  1997  to
continue this development project. As part of the San Juan  Basin
Transaction (discussed in more detail below), a third party  will
pay  100% of the capital necessary to enhance production from the
existing  NEBU  wells. Devon is entitled to  retain  75%  of  any
reserves in excess of those estimated to be in place at the  time
of  the  transaction  which are developed as  a  result  of  such
capital expenditures. See " - San Juan Basin Transaction" below.

      Over  the  longer  term, drilling infill  wells  on  denser
spacing  or  utilizing  enhanced  recovery  techniques  such   as
injecting  carbon dioxide or nitrogen into the coal formation  to
force  additional gas to the producing well bores, may result  in
further  NEBU reserve and production increases. Devon  and  other
owners  in the San Juan Basin have studied and experimented  with
these  various options to determine if additional recoveries  are
economically feasible. Such development projects, if  undertaken,
would   likely   result   in   significant   additional   capital
expenditures;  however,  the  timing  of  any  such  projects  is
presently  unknown.  The  third  party  in  the  San  Juan  Basin
Transaction  is not obligated to pay any capital or  entitled  to
receive  any  reserves associated with any new  or  infill  wells
drilled at NEBU.

      32-9  Unit.   The 32-9 Unit is located approximately  eight
miles  northwest  of  NEBU. Geologically and  operationally  this
property is very similar to NEBU: the coal seams at the 32-9 Unit
are about the same thickness as at NEBU, the type of coal and the
depth at which it is found are similar and the gas content of the
coal is estimated to be approximately the same. However, the 32-9
Unit  is located in an area where the coal does not appear to  be
as  permeable  as  it is at NEBU. 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 and possibly increase reserves; however, the timing of
such  drilling, if it occurs, is unknown. This unit is also being
evaluated for possible mechanical improvements similar  to  those
being implemented at NEBU.

      San  Juan  Basin Transaction.  Effective January  1,  1995,
Devon  and  an  unrelated  company  entered  into  a  transaction
covering  substantially all of Devon's San Juan Basin  coal  seam
properties. The effect of the transaction is that the price Devon
receives  for  its coal seam gas production will be approximately
$0.55  to  $0.60  per Mcf (subject to adjustment  for  inflation)
higher  than the price the Company would otherwise receive during
the  period  from  1995  through the year 2002.  For  a  detailed
discussion   of  this  transaction,  see  note   3   to   Devon's
consolidated financial statements included elsewhere herein.

Title to Properties

      Title  to properties is subject to contractual arrangements
customary  in  the oil and gas industry, liens for current  taxes
not  yet  due  and, in some instances, other encumbrances.  Devon
believes  that  such burdens do not materially detract  from  the
value of such properties or from the respective interests therein
or  materially interfere with their use in the operation  of  the
business.

      As  is customary in the industry in the case of undeveloped
properties, little investigation of record title is made  at  the
time  of  acquisition (other than a preliminary review  of  local
records).  Investigations, generally including a title opinion of
outside  counsel,  are  made  prior to  the  consummation  of  an
acquisition  of 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

     A special meeting of Devon shareholders was held on December
6, 1996. The purpose of the meeting was to consider and vote upon
two  issues: (a) the issuance of 9,954,000 shares of Devon common
stock   to   Kerr-McGee   in  connection  with   the   Kerr-McGee
Transaction;  and  (b)  an amendment to  Devon's  certificate  of
incorporation  to  increase the number of  authorized  shares  of
Devon common stock from 120 million shares to 400 million shares.

      Out  of  a  total  of  22,130,896 shares  of  common  stock
outstanding and entitled to vote, 18,773,628 shares, or 85%, were
represented at the meeting in person or by proxy.

      Each  of  the proposals being voted upon was approved.  The
voting results were as follows:
<TABLE>
<CAPTION>

                     Proposal (a)           Proposal (b)
              ----------------------     -----------------
              Shares        % (1)     Shares     % (1)
              ------        -----     ------     -----
<S>           <C>           <C>       <C>           <C>

For           18,508,262    83.6%     17,451,728    78.9%
Against           15,538     0.1%      1,287,950     5.8%
Abstain           32,254     0.2%         33,950     0.2%
Broker Non-Vote  217,574     1.0%             --       --

(1)  Percent of total shares outstanding and entitled to vote.
</TABLE>

                            PART II



ITEM 5.   MARKET  FOR  REGISTRANT'S  COMMON  EQUITY  AND  RELATED
          STOCKHOLDER MATTERS

Market Price

      Devon's common stock has been traded on the American  Stock
Exchange  (the  "AMEX")  since  September  29,  1988.  Prior   to
September 29, 1988, Devon's common stock was privately held.

     The following table sets forth the high and low sales prices
for  Devon  common stock as reported by the AMEX for the  periods
indicated.
<TABLE>
<CAPTION>
                                                          Average
                                                            Daily
                                      High     Low         Volume
                                    ------   ------      --------
<S>                                 <C>      <C>         <C>
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   19-7/8      44,846
Quarter Ended June 30, 1996         26-1/8   22          39,268
Quarter Ended September 30, 1996    27-1/2   22-3/4      73,678
Quarter Ended December 31, 1996     36-7/8   25-1/4      93,606
1997:                                                            
Quarter Ended March 31, 1997        38-7/8   31          74,876
(through February 24, 1997)
</TABLE>

Dividends

      Devon  commenced  the  payment of  regular  quarterly  cash
dividends on its common stock on June 30, 1993, in the amount  of
$0.03 per share. Total dividends for the years ended December 31,
1994  and 1995 were $0.12 per share. Effective December 31, 1996,
Devon  increased  its  quarterly dividend payment  to  $0.05  per
share, making the total dividends paid in 1996 equal to $0.14 per
share.   Devon  anticipates continuing to pay  regular  quarterly
dividends in the foreseeable future.

      On  February 24, 1997, there were approximately  900  Devon
Common Stock shareholders of record.

  ITEM 6.   SELECTED FINANCIAL DATA

       The  following selected financial information (not covered
  by  the  independent  auditors'  report)  should   be  read  in
  conjunction  with "Item 7. Management's Discussion and Analysis
  of  Financial Condition  and Results  of  Operations," and  the
  consolidated  financial  statements  and   the  notes   thereto
  included  in  "Item 8.  Financial Statements  and Supplementary
  Data."
<TABLE>
<CAPTION>
                                                 Year Ended December 31,
                                        1996    1995     1994    1993      1992
                                          (Thousands, Except Per Share Data)

  OPERATING RESULTS

     <S>                      <C>      <C>     <C>      <C>     <C>       <C>
     Oil sales                $        80,142  55,290   38,086  38,395    27,329
     Gas sales                         68,049  50,732   56,372  54,876    39,973
     NGL sales                         14,367   6,404    4,908   4,544     1,370
     Other revenue                      1,459     877    1,407     942     2,892

     Total revenues           $       164,017 113,303  100,773  98,757    71,564

     Lease operating expenses $        31,568  27,289   24,521  26,401    18,430
     Production taxes         $        10,658   6,832    6,899   6,924     4,600
     Depreciation, depletion
        and amortization      $        43,361  38,090   34,132  28,409    19,894
     General and administra-
        tive expenses         $         9,101   8,419    8,425   7,640     6,510
     Interest expense         $         5,277   7,051    5,439   3,422     2,644
     Distributions on preferred
       securities of subsidiary
       trust                  $         4,753      --       --      --        --

<F1>
     Net earnings             $        34,801  14,502   13,745  20,486 1  14,615

     Net earnings per share:
<F1>
       Assuming no dilution   $          1.57    0.66     0.64    0.98 1    0.94
<F1>
       Assuming full dilution $          1.52    0.66     0.64    0.98 1    0.90

     Cash dividends:
       Per preferred share    $            --      --       --      --      1.46
       Per common share       $          0.14    0.12     0.12    0.09        --

     Weighted average common
       shares outstanding              22,160  22,074   21,552  20,822    13,802

<F2>
     Ratio of earnings to fixed
       charges 2              $          6.76    4.54     4.80    8.24      7.97

  BALANCE SHEET DATA

     Total assets             $       746,251 421,564  351,448 285,553   225,972
     Long-term debt           $         8,000 143,000   98,000  80,000    54,450
     Convertible preferred
        securities of
        subsidiary trust      $      149,500      --       --       --        --
     Stockholders' equity     $      472,404 219,041  206,406  172,900   153,267

<PAGE>
<CAPTION>
                                                                
                                                  Year Ended December 31,
                                       1996    1995     1994    1993       1992
CASH FLOW DATA

     Net cash provided by
        operating activities  $       86,802  61,276   46,384  63,957     30,499
<F4>
<F3>
     EBITDA 3,4                      112,689  70,763   60,928  57,792     42,024
<F5>
<F4>
     Cash margin 4,5                  95,951  59,217   55,074  52,893     38,140

PRODUCTION, PRICE AND OTHER DATA

     Production:
            Oil (MBbls)                3,816   3,300    2,467   2,337      1,446
            Gas (MMcf)                35,714  36,886   39,335  35,598     28,374
            NGLs (MBbl)                  952     600      501     411        112
<F6>
            MBoe 6                    10,720  10,047    9,524   8,681      6,287

     Average prices:
            Oil (Per Bbl)        $     21.00   16.75    15.44   16.43      18.89
            Gas (Per Mcf)        $      1.91    1.38     1.43    1.54       1.41
            NGLs (Per Bbl)       $     15.09   10.68     9.79   11.06      12.28
<F6>
            Per Boe 6            $     15.16   11.19    10.43   11.27      10.92

     Costs per Boe:
            Operating costs      $      3.94    3.40     3.30    3.84       3.66
            DD&A of oil and gas
               properties        $      3.88    3.65     3.45    3.16       3.08
            General and
              administrative
              expenses           $      0.85    0.84     0.89    0.88       1.04

                                             
<F1>
   1  Net earnings  for 1993 include  the cumulative  effect of  a
     required change in the method of accounting for income taxes
     in 1993 which  provided earnings of  $1.3 million, or  $0.06
     per share.

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

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

<F4>
   4  EBITDA  and cash  margin are  indicators which  are commonly
     used in  the oil and gas  industry.  They should  be used as
     supplements to, and not as substitutes for, net earnings and
     net  cash provided  by  operating  activities determined  in
     accordance with generally  accepted accounting principles in
     analyzing Devon's results of operations and liquidity.

     For  the years ended December 31, 1996, 1995, 1994, 1993 and
     1992,  net  cash used  in  investing  activities were  $94.8
     million,  $110.6 million, $73.4  million, $74.2  million and
     $140.6 million,  respectively.  For these  same periods, net
     cash  provided by  financing  activities were  $8.5 million,
     $49.8  million,  $15.8  million, $24.2  million  and  $107.9
     million, respectively.

<F5>
   5  "Cash  margin"  equals  total revenues  less  cash expenses.
     Cash  expenses  are all  expenses  other  than the  non-cash
     expenses of  depreciation,  depletion and  amortization  and
     deferred  income tax expense.   Cash margin measures the net
     cash which is  generated by a company's  operations during a
     given period,  without  regard to  the period  such cash  is
     actually physically received or spent by the company.   This
     margin  ignores the  non-operational effect  on  a company's
     "net cash provided by  operating activities", as measured by
     generally accepted accounting  principles, from a  company's
     activities  as an  operator  of oil  and  gas wells.    Such
     activities produce  net increases or decreases  in temporary
     cash funds held by  the operator which have no effect on net
     earnings of the company.

<F6>
   6  Gas is converted to Boe  or MBoe at the  rate of six Mcf  of
     gas per barrel of  oil, based upon the approximate  relative
     energy content of  natural gas  and oil, which  rate is  not
     necessarily indicative  of the  relationship of oil  and gas
     prices.  The respective  prices  of oil,  gas  and NGLs  are
     affected by market and other factors in addition to relative
     energy content.
</TABLE>
<PAGE>

  ITEM 7.   MANAGEMENT'S  DISCUSSION  AND ANALYSIS  OF  FINANCIAL
            CONDITION AND RESULTS OF OPERATIONS

       The following  discussion and  analysis addresses  changes
  in  Devon's  financial  condition  and  results  of  operations
  during the  three year period  of 1994 through 1996.  Reference
  is  made to  "Item  6. Selected  Financial  Data" and  "Item 8.
  Financial Statements  and Supplementary Data."

  Overview

       Devon  concluded 1996 financially stronger and larger than
  at any  previous time in the  company s history.  Over the last
  three  years Devon's  oil and gas  reserves have  grown 129% to
  179 million barrels of oil equivalent  ("MMBoe"). The company s
  long-term  credit  lines  have  increased  63%  over  the  same
  period, to $260 million.   Total assets have increased  161% to
  $746 million. During  the same  three years  Devon reduced  its
  long-term   debt  from   $80   million   to  $8   million   and
  significantly increased stockholders  equity.

       Devon's  operating performance  has also  improved by most
  measures  over  the last  three  years.  In  1996  oil and  gas
  production was 23% over that  of 1993, to 10.7 MMBoe. The  1996
  production  increase  coupled with  a 35%  increase in  oil, gas
  and NGL prices over 1993  levels, led  to revenues and  earnings gains.
  Net earnings for 1996  climbed 70% over those of 1993, to $34.8
  million. Net  cash provided by  operating activities rose  from
  $46.4 million  in  1994 to  $61.3  million  in 1995  and  $86.8
<F1>
  million  in 1996.  The  cash margin1 (total  revenues less cash
  expenses)  during these  same three  years  has increased  from
  $55.1 million  in  1994 to  $59.2  million  in 1995  and  $96.0
  million in 1996.

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

            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,  production and
            revenues in the San Juan Basin.

            Devon  acquired   the  properties   of  Alta   Energy
            Corporation through  a  $72 million  cash and  common
            stock merger in May 1994.  The oil and gas properties
                              

<F1>
1   "Cash margin" equals Devon's total revenues less cash expenses.   Cash
     expenses are all expenses other than  the non-cash  expenses  of
     depreciation,  depletion  and amortization  and  deferred income  tax
     expense.   Cash margin is  an indicator  which is commonly  used in  the
     oil and  gas industry.   This margin measures the  net cash  which is
     generated  by a  company's operations during  a given  period,
     without regard to the period such cash is actually physically  received
     or spent by the company.  This margin ignores  the non-operational effects
     on  a company's activities as  an operator of  oil and gas wells.
     Such activities  produce net  increases or  decreases in  temporary cash
     funds held  by the operator which  have no  effect on  net earnings  of
     the company.   Cash  margin should  be used  as a supplement  to, and 
     not  as  a substitute  for,  net  earnings and  net  cash provided  by
     operating activities  determined  in  accordance with  generally
     accepted  accounting  principles in  analyzing Devon's results of
     operations and liquidity.


            acquired  through  the  merger   (the  "Alta   Merger
            Properties") added substantial oil and  gas reserves,
            production  and  revenues  to  Devon's Permian  Basin
            position.

            Devon  acquired  additional  interests in  certain of
            its Wyoming oil and natural gas properties and  a gas
            processing  plant  (the  "Worland  Properties")   for
            approximately   $57   million  from   December,  1995
            through April, 1996.

            In 1995, Devon  entered into  a transaction  covering
            substantially all  of its  San Juan  Basin coal  seam
            gas properties  (the "San  Juan Basin  Transaction").
            This transaction  added approximately  $10 million to
            Devon's annual revenues.

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

            Devon  has  been  successful  during  the  last three
            years  in its  drilling  efforts.   Devon  has  spent
            approximately  $171 million  to drill  476  wells, of
            which 462 were completed as producers.
   

       The  following  actions   during  the  last  three   years
  improved  Devon s  liquidity  and  financial   resources  while
  reducing its bank debt:

            The  issuance  of  $22 million  of  additional common
            equity capital in 1994 for the 1994 Alta Merger.

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

            Devon's acquisition  and drilling  efforts during the
            last three  years have  added 126.5  MMBoe of  proved
            reserves to its asset base.  Combined  with 8.6 MMBoe
            of  upward   revisions  to   its  reserve  estimates,
            Devon's  total  reserve   additions  of  135.1  MMBoe
            during  the  past  three  years  were   446%  of  its
            production of 30.3 MMBoe.

            In  July,   1996,  Devon,   through  a   newly-formed
            affiliate  trust, issued $149.5 million of 6.5% Trust
            Convertible    Preferred   Securities    (the    "TCP
            Securities").

            Devon's  oil and  gas  reserve  additions, production
            gains, revenue  increases and  equity additions  over
            the past three  years have allowed Devon to  increase
            its lines of credit.   Since the end of 1993, Devon's
            long-term  credit   lines  have  increased  by   $100
            million to a total of $260 million at year-end 1996.

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

       While  Devon  has  consistently increased  production over
  this  period of  time,  volatility in  oil  and gas  prices has
  resulted  in  considerable  variability  in  earnings  and cash
  flows.   Prices for oil, natural  gas and  NGL s are determined
  primarily  by prevailing market conditions.   Market conditions
  for  these  products  have  been,  and  will  continue  to  be,
  influenced by regional and world-wide  economic growth, weather
  and other  factors that are  beyond Devon's  control.   Devon's
  future earnings  and cash flows  will continue to be  dependent
  on market conditions for the company s production.

       Like all  oil and  gas production  companies, Devon  faces
  the  challenge of  natural decline.   As  virgin pressures  are
  depleted,  oil and  gas production from  a given well naturally
  decreases. Thus,  an oil  and gas  production company  consumes
  part of  its asset  base  with each  unit  of  oil and  gas  it
  produces.   Historically, Devon has been  able to overcome this
  natural decline  by adding more  reserves through drilling  and
  acquisitions  than the  company produces.    However,   Devon's
  future growth, if any,  will depend on the company's ability to
  continue to add reserves in excess of production. 

       Because Devon  can only marginally  influence oil and  gas
  prices, the  company's management  has focused  its efforts  on
  increasing  oil  and   gas  reserves  and  production  and   on
  controlling expenses.  Over  its eight year history as a public
  company,  Devon  has  been able  to  significantly  reduce  its
  production  and  operating   costs  per  unit  of   production.
  However, over  the last  two years  Devon's per-unit  operating
  costs have  increased somewhat.  An increase  in the  company's
  oil production  as a  portion of  its total  production and  an
  increase  in  secondary recovery  projects have  contributed to
  this  expense  increase.   (Producing  oil  is  generally  more
  expensive  than  producing  gas.    Also,  secondary   recovery
  projects   are   generally    more   expensive   than   primary
  production.)  Higher oil and  gas prices in 1996  also resulted
  in  higher production  taxes,  a  component of  production  and
  operating expenses.   Devon's  future earnings  and cash  flows
  are dependent on the company's  ability to continue to  contain
  production  and  operating  costs  at  levels  that  allow  for
  profitable production of its oil and gas.


  Results of Operations

       Devon's total revenues  have risen from $100.8 million  in
  1994  to $113.3 million in 1995 and $164.0 million in 1996.  In
  each of these years, oil, gas  and NGL sales accounted for  99%
  of total revenues.

       Changes  in  oil,  gas  and  NGL  production,  prices  and
  revenues from 1994 to 1996 are shown in the table below.
<TABLE>
<CAPTION>
                                            Year Ended December  31, 
                                               1996          1995
                                      1996   vs 1995  1995  vs 1994  1994

  Production
    <S>                               <C>      <C>    <C>     <C>    <C>
    Oil (MBbls)                       3,816    +16%   3,300   +34%   2,467
    Gas (MMcf)                       35,714     -3%  36,886    -6%  39,335
    NGLs (MBbls)                        952    +59%     600   +20%     501
    Oil, Gas and NGLs (MBoe)         10,720     +7%  10,047    +5%   9,524

  Revenues
    Per Unit of Production:
      Oil (per Bbl)                 $ 21.00    +25%   16.75    +8%   15.44
      Gas (per Mcf)                   $1.91    +38%    1.38    -3%    1.43
      NGLs (per Bbl)                $ 15.09    +41%   10.68    +9%    9.79
      Oil, Gas and NGLs (per Boe)   $ 15.16    +35%   11.19    +7%   10.43

    Absolute:                                    (Thousands)
      Oil                           $80,142    +45%  55,290   +45%  38,086
      Gas                           $68,049    +34%  50,732   -10%  56,372
      NGLs                          $14,367   +124%   6,404   +30%   4,908
      Oil, Gas and NGLs            $162,558    +45% 112,426   +13%  99,366
</TABLE>

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

       The  Grayburg-Jackson  Field  acquired  in the  1994  Alta
  Merger  accounted   for  the   majority  of  1996's   increased
  production.   This field produced 1,108,000  barrels in 1996, a
  37% increase  over the  807,000 barrels the  field produced  in
  1995.  Production  from Devon's other oil properties  increased
  9%  in  1996,  from  2,493,000  barrels  in  1995 to  2,708,000
  barrels in 1996.

       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  Grayburg-Jackson  Field  produced 807,000  barrels in
  1995,  a 296%  increase  from  the 204,000  barrels  which were
  produced during Devon's ownership  for the last seven months of
  1994.  Production  from Devon's other oil properties  increased
  10%  in  1995, from  2,263,000  barrels  in 1994  to  2,493,000
  barrels in 1995.

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

       Coal seam gas  production declined  by 16%, from  20.8 Bcf
  in  1995 to 17.4  Bcf in 1996.   However,  the average realized
  coal seam gas price  rose by 30% from $1.32 per Mcf in  1995 to
  $1.72  per Mcf  in 1996.   Total  coal seam  gas revenues  were
  $30.1 million in 1996 compared to $27.5 million in 1995.   Coal
  seam  gas revenues  include  $10.3  million in  1996  and $12.8
  million   in  1995   attributable  to   the   San  Juan   Basin
  Transaction.

       Total  conventional gas production  and revenues  for 1996
  were 18.3 Bcf  and $37.9 million, respectively, versus 16.1 Bcf
  and  $23.2 million  in  1995.    Prices  for  conventional  gas
  averaged $2.08  per Mcf in 1996  compared to  1995's average of
  $1.44.   The  additional interests  in  the Worland  Properties
  which were  acquired in  December 1995  and the  first half  of
  1996 added 2.2 Bcf to 1996's conventional production.

       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  Alta   Merger
  Properties,  as   opposed  to  only   seven  months  in   1994,
  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 contributors  to the
  conventional production decline  in 1995 were the Ozona  field,
  miscellaneous property sales and NEBU.   High pipeline pressure
  and down  time for repairs contributed  to a  0.6 Bcf reduction
  in Ozona  production in 1995.   Various marginal  wells sold in
  1994  and 1995  accounted  for a  0.6  Bcf reduction  in 1995's
  conventional  production.   Out-of-period marketing adjustments
  caused the  reduction in  1995 conventional  gas production  at
  NEBU.

       Although Devon  does not  have a  significant interest  in
  conventional gas production in  NEBU, it had been  selling more
  than  its  normal  share  of   production.    This  created  an
  "imbalance" between  Devon and the  wells' other owners.   This
  imbalance was  reversed in 1995 as  the other  owners sold more
  than  their normal  share of production.   Also  in 1994, Devon
  received  nonrecurring  payments for  inventory gas  from NEBU.
  In 1995, the amounts  of imbalance makeup and lack of inventory
  sales  led  to  a  0.5  Bcf  reduction  in   conventional  NEBU
  production compared to 1994.

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

       The   additional  interests   acquired   in   the  Worland
  Properties  in  December  1995  and  the  first  half  of  1996
  accounted for  214,000 barrels of  the increased production  in
  1996.   The Worland Properties produced 226,000 barrels in 1996
  compared  to 12,000 barrels  in 1995.   Additional  drilling in
  the Sand Dunes  area of the Permian Basin  increased production
  from 69,000 barrels in 1995 to 95,000 barrels in 1996.

       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  Alta Merger Properties  accounted for  52,000 barrels
  of the increased  production.  Such properties produced  84,000
  barrels  in 1995,  compared to 32,000  barrels during the seven
  months  Devon  owned  the  properties  in   1994.    Additional
  drilling  in the  Sand  Dunes  area increased  production  from
  39,000 barrels in 1994 to 69,000 barrels in 1995. 

       Expenses   The details of the  changes in pre-tax expenses
  between 1994 and 1996 are shown in the table below.
<TABLE>
<CAPTION>
                                                                
                                                           Year Ended December 31,
                                                         1996                1995
                                                  1996  vs 1995    1995    vs 1994    1994
                                                    (Absolute Amounts in Thousands)

  Absolute:
    Production and operating expenses:
      <S>                                     <C>         <C>     <C>       <C>     <C>
      Lease operating expenses                $ 31,568    +16%    27,289    +11%    24,521
      Production taxes                          10,658    +56%     6,832     -1%     6,899
    Depreciation, depletion and amortization
       attributable to:
      Oil and gas production                    41,538    +13%    36,640    +11%    32,861
      Non-oil and gas properties                 1,823    +26%     1,450    +14%     1,271
    General and administrative expenses          9,101     +8%     8,419      -      8,425
    Interest expense                             5,277    -25%     7,051    +30%     5,439
    Distributions on preferred securities of 
     subsidiary trust                            4,753     N/A         -      -          -

        Total                                $ 104,718    +19%    87,681    +10%    79,416

<F1>
  Per Boe Produced(1):
    Production and operating expenses:
      Lease operating expenses                   $2.95     +8%      2.72     +6%      2.57
      Production taxes                            0.99    +46%      0.68     -7%      0.73
    Depreciation, depletion and amortization
     attributable to:
      Oil and gas production                      3.88     +6%      3.65     +6%      3.45
      Non-oil and gas properties                  0.17    +21%      0.14     +8%      0.13
    General and administrative expenses           0.85     +1%      0.84     -6%      0.89
    Interest expense                              0.49    -30%      0.70    +23%      0.57
    Distributions on preferred securities of 
     subsidiary trust                             0.44     N/A         -      -          -

       Total                                     $9.77    +12%      8.73     +5%      8.34

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

</TABLE>

     Production  and  Operating  Expenses   The  details  of  the
  changes in production  and operating expenses between 1994  and
  1996 are shown in the table below.

<TABLE>
<CAPTION>
                                                    Year Ended December 31,  
                                                     1996               1995
                                            1996   vs 1995     1995   vs 1994    1994
                                               (Absolute Amounts  in  Thousands)
  Absolute:
    <S>                                   <C>         <C>     <C>       <C>     <C>
    Recurring lease operating expenses    $ 28,270    +19%    23,842    +10%    21,583
    Well workover expenses                   3,298     -4%     3,447    +17%     2,938
    Production taxes                        10,658    +56%     6,832     -1%     6,899

       Total production and operating
         expenses                         $ 42,226    +24%    34,121     +9%    31,420

  Per Boe:
    Recurring lease operating expenses    $   2.64    +11%      2.37     +4%      2.27
    Well workover expenses                    0.31    -11%      0.35    +17%      0.30
    Production taxes                          0.99    +46%      0.68     -7%      0.73

       Total production and operating
         expenses                         $   3.94    +16%      3.40     +3%      3.30

</TABLE>
     1996 vs. 1995   Recurring lease operating expenses increased
  by $4.4 million, or 19%,  in 1996.  Approximately  $2.7 million
  of  the  increase  was  related  to  the  additional  interests
  acquired in  the Worland  Properties in December  1995 and  the
  first  half of  1996.   Recurring lease operating  expenses for
  the Worland  Properties increased from $0.1  million in 1995 to
  $2.8 million in  1996 after  Devon increased  its ownership  in
  such properties.   The Alta Merger Properties' recurring  lease
  operating expenses increased from $3.5 million in  1995 to $4.6
  million in  1996.  This increase  was predominantly  due to the
  higher number of producing wells in  the Grayburg-Jackson Field
  in 1996 compared to 1995.

     Recurring expenses per Boe were up by $0.27, or 11%, in 1996
  compared to  1995.  This increase  was primarily  caused by the
  reduction in  the coal  seam  gas  properties' share  of  total
  production.  The  recurring operating costs per  Boe for  these
  coal seam  gas properties are extremely  low ($0.32  per Boe in
  1996 and $0.24 per Boe  in 1995).  However, as production  from
  these  properties declined  and production  from  Devon's other
  properties increased  in 1996,  the coal  seam gas  properties'
  percentage of  overall production dropped  from 35% in 1995  to
  27%  in 1996.  The result is that more of Devon's production in
  1996  was  attributable   to  its  conventional  oil  and   gas
  properties, which  have a higher  recurring operating cost  per
  Boe than the low-cost  coal seam gas properties.  The recurring
  costs per  Boe on  Devon's conventional  properties were  $3.50
  per Boe  in 1996  and 1995.   However,  since these  properties
  represented a larger percentage of Devon's  total production in
  1996 compared to 1995, the result was a $0.27 per  Boe increase
  in the overall rate.

     Production taxes are collected by most taxing authorities on
  a fixed  percentage of  revenue basis.   Therefore, as  Devon's
  revenues have increased, so have production  taxes.  Production
  taxes increased 56% from  $6.8 million in 1995 to $10.7 million
  in 1996.   This increase was  due almost  exclusively to higher
  oil, gas and NGL  revenues.  Excluding revenues generated  from
  the  San  Juan  Basin  Transaction  which  are not  subject  to
  production taxes, 1996  oil, gas and NGL revenues increased 53%
  compared to 1995.

     Production  taxes per Boe increased by $0.31 per Boe, or 46%
  in  1996.   This was primarily  caused by  the increase  in the
  average price per Boe received  in 1996.  Excluding  the effect
  on average prices from the San Juan  Basin Transaction, Devon's
  total revenues  per Boe increased by 43%  from $9.92 per Boe in
  1995 to $14.21 per Boe in 1996.

     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  Alta Merger  Properties.
  Costs for  these properties 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 Alta  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.

     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.

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

     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 Alta  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.

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

     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.

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

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

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

     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  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.

     Distributions  on Preferred  Securities of  Subsidiary Trust
  1996  vs.  1995    As  mentioned  in  the  above  discussion of
  interest  expense,   and  as   discussed  in  Note   9  to  the
  consolidated  financial  statements included  elsewhere herein,
  Devon,  through  its  newly-formed  affiliate  Devon  Financing
  Trust, completed  the issuance  of $149.5 million  of 6.5%  TCP
  Securities  in  a  private   placement  in  July  1996.     The
  distributions accrue  at the rate of  1.625% per  quarter.  The
  1996 distributions  of $4.8  million represented slightly  less
  than  two quarters'  distributions  due  to the  issuance  date
  occurring in July.

     Income  Taxes   1996  vs. 1995   Devon's effective financial
  tax rate  in 1996  was 41%,  compared  to 1995's  rate of  43%.
  Both  rates were  above the statutory  federal tax  rate of 35%
  due to state income  taxes, and certain tax aspects of  the San
  Juan Basin Transaction and the 1994 Alta Merger.  

     1995 vs 1994   Devon's effective financial tax rate  in 1995
  was 43%, compared  to 1994's rate of  36%.  State  income taxes
  and certain tax aspects  of the San Juan Basin Transaction were
  the primary factors which increased Devon's  financial tax rate
  in  1995.    The  San   Juan  Basin  Transaction  also   had  a
  significant effect  on the  portion of income  taxes which  are
  current versus deferred.

  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  $98.9 million  of cash
  was  spent in  1996  for capital  expenditures, of  which $85.0
  million  was   related   to   the  acquisition,   drilling   or
  development of  oil and gas properties.   Most  of the drilling
  and development efforts in 1996 centered in  the Permian Basin,
  which  included 176  of the 194  oil and gas  wells which Devon
  drilled during  1996.   Most of  Devon's 1996  non-oil and  gas
  property  related  capital  expenditures  involved   the  $12.5
  million purchase of  the office building in which  its Oklahoma
  City  offices  are  located.    This  purchase  was  closed  on
  December 31, 1996.

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

     Capital  Resources  and  Liquidity   Net  cash  provided  by
  operating activities  ("operating cash  flow") was the  primary
  source of capital and short-term liquidity in 1996.   Operating
  cash  flow  in  1996  totaled  $86.2  million,  a 41%  increase
  compared to the $61.3  million of operating cash flow generated
  in 1995.

     In  addition to  operating cash  flow, Devon's  credit lines
  have  been an  important source of  capital and  liquidity.  At
  year-end 1996, long-term credit lines totaled  $260 million, of
  which $252 million was  available for future  use.  At the  end
  of 1996,  in connection  with the  KMG-NAOS acquisition,  Devon
  also established  a demand  revolving credit  line for  its new
  Canadian operations.   This  credit line  totals $12.5  million
  Canadian  dollars, all  of  which  was available  at  year-end.
  (See Note 7  to the consolidated financial statements  included
  elsewhere in  this  report  for a  detailed  discussion of  the
  credit  lines.)    The   use  of  the  proceeds  from  the  TCP
  Securities  offering in  July  1996  to retire  long-term  debt
  increased  the amount  of Devon's  credit  lines available  for
  future borrowings.

     Devon's San Juan Basin  coal seam gas production is  subject
  to uncertainties regarding additional royalties and  taxes.  If
  such uncertainties  are resolved in  1997, the resolutions  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 12 to the  consolidated
  financial statements contained elsewhere in this report.

  1997 Estimates

       The   forward-looking   statements   provided   in    this
  discussion are based  on management's examination of historical
  operating  trends, the  December 31,  1996  reserve reports  of
  LaRoche  and  AMH,  data  in   Devon's  files  and  other  data
  available from  third parties. Devon  cautions that its  future
  oil, gas and NGL production, revenues and expenses are  subject
  to all of the  risks and uncertainties normally incident to the
  exploration for and development  and production of oil and gas.
  These  risks include,  but are  not  limited to,  environmental
  risks, drilling  risks,  regulatory  changes,  the  uncertainty
  inherent  in  estimating  future  oil  and  gas  production  or
  reserves, and  other risks  as  outlined  below. The  scope  of
  Devon s operations  increased significantly  with the  KMG-NAOS
  transaction. This  increases the  margin of  error inherent  in
  estimating  Devon s   1997  production   volumes,  prices   and
  expenses.    Also,  the  financial  results   for  Devon's  new
  Canadian operations, obtained in the KMG-NAOS transaction,  are
  subject to currency exchange rate risks. 

       Assumptions and Risks for Price and  Production Estimates 
  Prices for oil,  natural gas and NGLs are  determined primarily
  by prevailing market  conditions.  Market conditions for  these
  products  are influenced  by regional  and world-wide  economic
  growth,  weather  and  other  substantially  variable  factors.
  These factors are  beyond Devon s control and are  difficult to
  predict.    Over 90%  of Devon s  revenues are  attributable to
  sales of these three commodities.   Consequently, the company s
  financial results and  resources are highly influenced by  this
  price volatility.

       Estimates for Devon s  future production  of oil,  natural
  gas  and NGLs  are based on  the assumption  that market demand
  and prices  for oil and gas will  continue at levels that allow
  for  profitable production of  these products. Although Devon's
  management  believes these assumptions to  be reasonable, there
  can be no assurance of such stability. 

       Certain of Devon s  individual oil and gas properties  are
  sufficiently significant  as to have  a material impact on  the
  company s  overall financial  results.    With respect  to  oil
  production, these  properties include the  West Red Lake  Field
  and the  Grayburg-Jackson Unit, both  in southeast New  Mexico.
  The  company s interest  in NEBU and  the 32-9 Unit  can have a
  substantive effect on overall gas production.

       The  production,  transportation  and  marketing  of  oil,
  natural gas and  NGLs are complex processes  which are  subject
  to   disruption   due   to   transportation    and   processing
  availability,  mechanical failure,  human error, meteorological
  events  and  numerous  other  factors. The  following  forward-
  looking statements were prepared assuming  demand, curtailment,
  producibility and general  market conditions  for Devon's  oil,
  natural gas and NGLs  for 1997 will be substantially similar to
  those  of  1996,  unless otherwise  noted.  Given  the  general
  limitations   expressed    herein,   Devon's    forward-looking
  statements for 1997 are set forth below.

       Oil Production and Relative Prices  Devon expects its  oil
  production in  1997 to  total between  5.9 million  barrels and
  6.9  million barrels.   Devon expects  its net  oil prices will
  average  from between  $0.05 below  to $0.20  above West  Texas
  Intermediate posted prices in 1997.

       Gas  Production and  Relative Prices    Devon expects  its
  total gas production in 1997 will be between 64.0  Bcf and 75.0
  Bcf.   It  is expected  that coal  seam gas  production will be
  16.5  Bcf  to  19.5  Bcf.    Canadian  production  in  1997  is
  estimated  to be between  7.0 Bcf and  8.0 Bcf.   Devon expects
  production from  the remainder of its  gas properties  to total
  between 40.5 Bcf and 47.5 Bcf.

       Devon  expects its  1997 coal  seam average  price will be
  between  $0.25  and  $0.55  less  than  Texas  Gulf  Coast spot
  averages.   This  includes an expected  $0.55 per  Mcf from the
  San Juan  Basin Transaction.   Devon's Canadian gas  production
  is expected  to average from between  $0.85 to  $1.20 less than
  Texas Gulf  Coast spot prices.   (These Canadian  differentials
  are  expressed  in  U.S.  dollars,  using   the  year-end  1996
  exchange rate of  $0.73 U.S. dollar to $1.00  Canadian dollar.)
  Devon's remaining gas  production is expected to average  $0.05
  to $0.25 less than Texas Gulf Coast spot prices during 1997.

       NGL Production  Devon  expects its  production of NGLs  in
  1997  to total  between 1.1  million  barrels  and 1.3  million
  barrels.

       Production and Operating Expenses  Devon's  production and
  operating expenses vary  in response to several factors.  Among
  the  most  significant  of  these  factors   are  additions  or
  deletions   to  the   company's  property   base,  changes   in
  production taxes,  general changes  in the  prices of  services
  and materials that are used  in the operation of  the company's
  properties  and the  amount  of  repair and  workover  activity
  required on the company's properties. 

       The  addition of the KMG-NAOS Properties is expected to be
  the  largest contributor  to  an  increase in  recurring  lease
  operating   expenses  in   1997.     The   additional  revenues
  contributed by  these properties  should also cause  production
  taxes  to  rise.  In  addition,  well   workover  expenses  are
  anticipated to increase in 1997.  

       Oil,  gas and  NGL  prices will  have  a direct  effect on
  production taxes to be incurred  in 1997.  Future  prices could
  also have  an effect on whether  proposed workover projects are
  economically   feasible.   These   factors  coupled   with  the
  uncertainty of  future oil, gas  and NGL  prices, increase  the
  margin of  error inherent in  estimating future production  and
  operating  costs.  Given  these uncertainties,  Devon estimates
  that  1997's  total  production and  operating  costs  will  be
  between $75 million and $87 million.

       Depreciation, Depletion  and Amortization   The 1997  DD&A
  rate will depend on various  factors.  Most notable  among such
  factors are the amount of  proved reserves that could  be added
  from drilling or  acquisition efforts in 1997  compared to  the
  costs incurred for  such efforts, and the revisions  to Devon's
  year-end  1996 reserve  estimates  which  will be  made  during
  1997.  

       The DD&A rate as  of the beginning  of 1997 was $3.76  per
  Boe.  This rate includes  the effect of the December  31, 1996,
  acquisition of  the KMG-NAOS Properties.  Conversely, the  1996
  yearly rate  of $3.88  per Boe  did not reflect  the effect  of
  these properties.   Assuming a 1997  rate of  between $3.80 per
  Boe  and   $4.20  per   Boe,  1997   DD&A  expense   (including
  approximately $2.5 million of non-oil and  gas property related
  DD&A) is expected to be $76 million to $84 million.

       General  and Administrative Expenses   Devon's general and
  administrative expenses  include  the costs  of many  different
  goods and  services used in support  of the company's business.
  These goods and  services are  subject to  general price  level
  increases or decreases. In addition, Devon's  G&A expenses vary
  with the company's  level of activity and the  related staffing
  needs  as  well  as with  the  amount of  professional services
  required during  any given period. The addition of the KMG-NAOS
  Properties will increase  Devon's general level of activity  as
  well  as its  staffing  requirements  during 1997.  Should  the
  company's  anticipated needs  or  the  prices of  the  required
  goods  and  services differ  significantly  from  the company's
  expectations, actual  G&A expenses  could vary  materially from
  the  estimate.  Given  these  limitations,   G&A  expenses  are
  expected to be between $12 million and $14 million in 1997.

       Interest  Expense    Devon's  management  expects  to fund
  substantially  all of its  anticipated expenditures during 1997
  with  working  capital  and  internally  generated  cash  flow.
  Should  Devon's  actual   capital  expenditures  or  internally
  generated  cash  flow  vary  significantly  from  expectations,
  interest  expense could  differ  materially from  the following
  estimate. Given this  limitation, interest expense is  expected
  to be less than $1 million in 1997.

       Distributions  on  TCP  Securities    TCP  Securities  are
  convertible into  common shares of Devon  at the  option of the
  holder. Should any of the  holders of the TCP  Securities elect
  to convert during 1997,  it would reduce the amount of required
  distributions.  Assuming  all $149.5 million of TCP  Securities
  are  outstanding  for  the entire  year,  Devon will  make $9.7
  million of distributions in 1997. 

       Income Taxes  Devon expects its financial  income tax rate
  in 1997 to be between 38% and 42%.   Regardless of the level of
  pre-tax earnings reported  for financial  purposes, Devon  will
  have  a minimum  of  approximately  $2.5 million  of  financial
  income tax  expense due  to various  aspects of  the 1994  Alta
  Merger,  the  San  Juan  Basin  Transaction  and  the  KMG-NAOS
  acquisition.   Therefore, if the  actual amount of 1997 pre-tax
  earnings differs materially from what Devon currently  expects,
  the  actual  financial income  tax  rate  for  1997 could  fall
  outside  of the expected rate  of 38% to  42%.   Also, based on
  its  current  expectations   of  1997  taxable  income,   Devon
  anticipates its current  portion of  1997 income taxes  will be
  between $9  million and  $13  million.   However,  revenue  and
  earnings  fluctuations could  easily make  these  tax estimates
  obsolete.

       Capital Expenditures   Devon's capital expenditures budget
  is based  on an expected  range of future oil,  natural gas and
  NGL  prices  as well  as  the  expected  costs  of the  capital
  additions.  Should  the company's  price  expectations for  its
  future  production   change  significantly,  the  company   may
  accelerate or defer  some projects.  Thus, Devon would increase
  or decrease  total 1997 capital  expenditures. In addition,  if
  the  actual cost  of the  budgeted  items varies  significantly
  from the amount anticipated, actual  capital expenditures could
  vary materially from Devon's estimate. 

       Though Devon has completed 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.

       Given  these limitations,  Devon expects  its 1997 capital
  expenditures  for  drilling and  development  efforts  to total
  between $120 million and  $135 million, including $8 million to
  $11  million in  Canada.   (Canadian amounts  are expressed  in
  U.S. dollars, using  the year-end 1996 exchange  rate of  $0.73
  U.S. dollar to $1.00  Canadian dollar.)  Devon expects to spend
  $50 million  to $65  million in  1997 for drilling,  facilities
  and waterflood costs  related to reserves classified as  proved
  as  of year-end 1996.   Devon also  plans to  spend another $15
  million to $20 million on new, higher risk/reward projects.

       Other  Cash Uses  Devon's management expects the policy of
  paying  a quarterly  dividend to  continue.   With  the current
  $0.05  per  share  quarterly dividend  rate  and  32.1  million
  shares  of  common   stock  outstanding,  1997  dividends   are
  expected to approximate $6.4 million.

       Capital  Resources and  Liquidity    The estimated  future
  drilling and development  activities are expected to be  funded
  through a combination of working capital and net  cash provided
  by  operations.  The amount  of  net  cash  to  be provided  by
  operating  activities in 1997 is  uncertain due  to the factors
  affecting revenues  and expenses cited  above.  However,  Devon
  considers its  capital resources  to be more  than adequate  to
  fund its anticipated capital expenditures.

       Based  on   the   expected   level   of   1997's   capital
  expenditures and  net cash provided  by operations, Devon  does
  not  expect to  rely  on its  credit lines  to fund  a material
  portion of its  capital expenditures.  However, if  significant
  acquisitions  or  other  unplanned  capital requirements  arise
  during  the year,  Devon could utilize  its credit  lines.  The
  unused  portion  of these  credit  lines  at  the  end of  1996
  consisted of $252  million of long-term credit facilities,  and
  a $12.5 million (Canadian dollars) demand  facility for Devon's
  new Canadian  operations.  If so  desired, Devon  believes that
  its lenders  would increase its credit  lines to  at least $450
  million to $500 million.  However, the company does not  desire
  nor anticipate a need  to increase its credit lines above their
  current levels.  In fact,  to lower its borrowing  costs, Devon
  may  reduce  its  credit   lines  in  1997  until  a  need  for
  significant capital arises.

       Impact  of Recently  Issued  Accounting Standards  Not Yet
  Adopted   In  June, 1996,  the  Financial Accounting  Standards
  Board issued  Statement of  Financial  Accounting Standard  No.
  125,  "Accounting  for  Transfers and  Servicing  of  Financial
  Assets and Extinguishments  of Liabilities."   SFAS No.  125 is
  effective  for  certain  transfers and  servicing  of financial
  assets  and  extinguishment   of  liabilities  occurring  after
  December 31,  1996.   It is  effective for  other transfers  of
  financial assets occurring after December  31, 1997.  It  is to
  be applied  prospectively.   SFAS No.  125 provides  accounting
  and   reporting  standards  for   transfers  and  servicing  of
  financial  assets and  extinguishment of  liabilities  based on
  consistent application of  a financial-components approach that
  focuses on  control.  It  distinguishes transfers of  financial
  assets  that  are   sales  from  transfers  that  are   secured
  borrowings.  Management of Devon  does not expect that adoption
  of  SFAS  No.  125  will  have  a  material  impact  on Devon's
  financial position or results of operations.

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

<PAGE>
  ITEM 8.      FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    Index to Consolidated Financial Statements and Consolidated
                   Financial Statement Schedules
                                                                 
                                                                        Page

  Independent Auditors' Report                                            43

  Consolidated Financial Statements:
     Consolidated Balance Sheets
          December 31, 1996, 1995 and 1994                                44

     Consolidated Statements of Operations
          Years Ended December 31, 1996, 1995 and 1994                    45

     Consolidated Statements of Stockholders' Equity
          Years Ended December 31, 1996, 1995 and 1994                    46

     Consolidated Statements of Cash Flows
          Years Ended December 31, 1996, 1995 and 1994                    47

     Notes to Consolidated Financial Statements
          December 31, 1996, 1995 and 1994                                48


  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, 1996,  1995 and  1994, and the
  results of their operations  and their cash flows for the years
  then ended,  in conformity  with generally accepted  accounting
  principles.





                                            KPMG Peat Marwick LLP

  Oklahoma City, Oklahoma
  February 7, 1997 
<PAGE>
<TABLE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
                    Consolidated Balance Sheets


<CAPTION>
                                                        December 31,                    
                                               1996         1995         1994

  Assets
  Current assets:
            <S>                            <C>            <C>         <C>
            Cash and cash equivalents      $  9,401,350   8,897,891   8,336,371
            Accounts receivable (Note 5)     29,580,306  14,400,295  15,626,799
            Inventories                       2,103,486     605,263     534,326
            Prepaid expenses                    688,752     222,135     564,371
            Deferred income taxes (Note 8)    1,600,000     749,000     262,000

              Total current assets           43,373,894  24,874,584  25,323,867

  Property and equipment, at cost, based
    on the full cost method of accounting
    for oil and gas properties (Note 6)     974,805,756 631,437,904 523,941,141
            Less accumulated depreciation,
              depletion and amortization    281,959,410 239,619,167 202,634,961

                                            692,846,346 391,818,737 321,306,180
  Other assets                               10,030,560   4,870,796   4,817,489

              Total assets                 $746,250,800 421,564,117 351,447,536

  Liabilities and stockholders' equity
  Current liabilities:
            Accounts payable:
              Trade                          4,861,428    3,868,458   6,394,897
              Revenues and royalties due
                to others                   10,569,960    7,322,418   7,398,199
            Income taxes payable             4,705,447    1,364,070           -
            Accrued expenses                 3,503,420    3,003,943   3,225,493

              Total current liabilities     23,640,255   15,558,889  17,018,589

  Revenues and royalties due to others       1,053,270      816,412   1,383,135
  Other liabilities (Notes 3 and 11)        10,325,999    8,623,057           -
  Long-term debt (Note 7)                    8,000,000  143,000,000  98,000,000
  Deferred revenue                             205,859       72,761   1,299,947
  Deferred income taxes (Note 8)            81,121,000   34,452,000  27,340,000

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

  Stockholders' equity (Note 10):
       Preferred stock of $1.00 par value.
         Authorized 3,000,000 shares; 
           none issued                               -            -           -
       Common stock of $.10 par value.  
         Authorized 400,000,000 shares;
           issued 32,141,295 in 1996,
           22,111,896 in 1995 and
           22,050,996 in 1994                3,214,130    2,211,190   2,205,100
       Additional paid-in capital          388,090,930  167,430,347 166,654,305
       Retained earnings                    81,099,357   49,399,461  37,546,460

           Total stockholders' equity      472,404,417  219,040,998 206,405,865 

  Commitments and contingencies
     (Notes 11 and 12)
           Total liabilities and
             stockholders' equity         $746,250,800  421,564,117 351,447,536


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


<CAPTION>
                                              Year Ended December 31,
                                            1996        1995          1994

  Revenues
            <S>                        <C>            <C>          <C>
            Oil sales                  $ 80,142,073   55,289,819   38,086,076
            Gas sales                    68,049,478   50,732,158   56,371,452
            Natural gas liquids sales    14,366,771    6,403,663    4,908,126
            Other                         1,458,562      877,185    1,407,305

               Total revenues           164,016,884  113,302,825  100,772,959

  Costs and expenses
            Lease operating expenses     31,568,428   27,288,755   24,520,757
            Production taxes             10,657,814    6,832,507    6,899,743
            Depreciation, depletion and
              amortization (Note 6)      43,361,029   38,089,783   34,132,150
            General and administrative
              expenses                    9,101,429    8,418,739    8,424,687
            Interest expense              5,276,527    7,051,142    5,438,911
            Distributions on preferred
              securities of subsidiary
              trust (Note 9)              4,753,125            -            -

               Total costs and expenses 104,718,352   87,680,926   79,416,248

  Earnings before income taxes           59,298,532   25,621,899   21,356,711

  Income tax expense (Note 8)
            Current                       6,709,000    4,495,000      415,000
            Deferred                     17,789,000    6,625,000    7,197,000

             Total income tax expense    24,498,000   11,120,000    7,612,000

  Net earnings                         $ 34,800,532   14,501,899   13,744,711

  Net earnings per average common
            share outstanding (Note 1):
             Assuming no dilution             $1.57         0.66         0.64
             Assuming full dilution           $1.52         0.66         0.64

  Weighted average common shares
    outstanding                           22,159,507   22,073,550  21,551,581




  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,
                                                    1996         1995          1994

  Common stock
             <S>                               <C>             <C>          <C>
             Balance, beginning of year        $  2,211,190    2,205,100    2,084,232
             Par value of common shares issued    1,002,940        6,090      120,868

             Balance, end of year                 3,214,130    2,211,190    2,205,100

  Additional paid-in capital
             Balance, beginning of year         167,430,347  166,654,305  144,403,743
             Common shares issued, net
              of issuance costs                 220,660,583      776,042    22,250,562

             Balance, end of year               388,090,930  167,430,347   166,654,305

  Retained earnings
             Balance, beginning of year          49,399,461   37,546,460    26,411,572
             Dividends                           (3,100,636)  (2,648,898)   (2,609,823)
             Net earnings                        34,800,532   14,501,899    13,744,711
   
             Balance, end of year                81,099,357   49,399,461    37,546,460

  Total stockholders' equity, end of year      $472,404,417  219,040,998   206,405,865




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


<CAPTION>
                                                             Year Ended  December 31,                           
                                                        1996           1995         1994

  Cash flows from operating activities
      <S>                                         <C>              <C>          <C>
      Net earnings                                $  34,800,532    14,501,899   13,744,711
      Adjustments to reconcile net earnings to net
        cash provided by operating activities:
           Depreciation, depletion and amortization  43,361,029    38,089,783   34,132,150
           (Gain) loss on sale of assets                 (3,930)      273,238      (27,086)
           Deferred income taxes                     17,789,000     6,625,000    7,197,000
           Changes in assets and liabilities net of
             effects of acquisitions of businesses
             (Note 2):
              (Increase) decrease in:
                 Accounts receivable                (15,470,528)    1,213,877      123,388
                 Inventories                           (176,286)      (70,937)     181,475
                 Prepaid expenses                      (466,617)      342,236          712
                 Other assets                        (1,032,653)      677,238     (489,648)
               Increase (decrease) in:
                 Accounts payable                     3,370,474      (430,736)  (8,896,674)
                 Income taxes payable                 3,341,377     1,364,070     (467,962)
                 Accrued expenses                       399,477      (221,550)     997,645
                 Revenues and royalties due to others   236,858      (566,723)     (62,748)
                 Long-term other liabilities            519,978       705,636            -
                 Deferred revenue                       133,098    (1,227,186)     (49,127)

                 Net cash provided by operating
                   activities                        86,801,809    61,275,845   46,383,836

  Cash flows from investing activities
      Proceeds from sale of property and equipment    4,037,480     9,427,401    4,649,257
      Capital expenditures                          (98,854,846) (117,593,897) (35,619,968)
      Payments made for acquisition of business
        (Note 2)                                              -    (2,391,484) (42,397,463)

                  Net cash used in investing
                    activities                      (94,817,366) (110,557,980) (73,368,174)

  Cash flows from financing activities
      Proceeds from borrowings on revolving
        line of credit                               29,000,000    52,000,000   32,500,000
      Principal payments on revolving line of
        credit                                     (164,000,000)   (7,000,000) (14,500,000)
      Issuance of common stock, net of issuance
        costs                                           577,483       782,132      380,244
      Issuance of preferred securities of subsidiary
        trust, net of issuance costs                144,665,205             -            -
      Dividends paid on common stock                 (3,100,636)   (2,648,898)  (2,609,823)
      Increase in long-term other liabilities
        (Note 3)                                      1,376,964     6,710,421            -

                  Net cash provided by financing
                    activities                        8,519,016    49,843,655   15,770,421

  Net increase (decrease) in cash and cash
    equivalents                                         503,459       561,520  (11,213,917)

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

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


  See accompanying notes to consolidated financial statements. 
</TABLE>
<PAGE>
             DEVON ENERGY CORPORATION AND SUBSIDIARIES
             Notes to Consolidated Financial Statements
                  December 31, 1996, 1995 and 1994


  1.           Summary of Significant Accounting Policies

               Accounting   policies   used   by   Devon   Energy
  Corporation   and   subsidiaries  ("Devon")   reflect  industry
  practices  and   conform  to   generally  accepted   accounting
  principles.  The more significant of such policies are  briefly
  discussed below.

  Basis of Presentation and Principles of Consolidation

               Devon   is  engaged  primarily   in  oil  and  gas
  exploration, development  and production,  and the  acquisition
  of producing properties.  Such  activities are primarily in the
  states of New  Mexico, Texas, Oklahoma, Wyoming and  Louisiana.
  Effective  December  31,  1996,   Devon  began  operations   in
  Alberta, Canada.   Devon's  share of  the assets,  liabilities,
  revenues  and  expenses  of  affiliated  partnerships  and  the
  accounts of its  wholly-owned subsidiaries are included in  the
  accompanying   consolidated   financial   statements.       All
  significant intercompany  accounts and  transactions have  been
  eliminated in consolidation.

  Use of Estimates in the Preparation of Financial Statements

               The   preparation   of  financial   statements  in
  conformity   with  generally   accepted  accounting  principles
  requires management  to  make  estimates and  assumptions  that
  affect  the reported  amounts  of  assets and  liabilities  and
  disclosure  of contingent assets and liabilities at the date of
  the financial statements, and the reported  amounts of revenues
  and  expenses during  the  reporting  period.   Actual  amounts
  could differ from those estimates.

  Inventories

               Inventories,  which  consist primarily  of tubular
  goods,  parts and  supplies,  are  stated at  cost,  determined
  principally by the average  cost method, which is not in excess
  of net realizable value.

  Property and Equipment

               Devon follows the  full cost method  of accounting
  for its  oil  and  gas  properties.    Accordingly,  all  costs
  incidental  to the acquisition, exploration  and development of
  oil  and   gas  properties,  including   costs  of  undeveloped
  leasehold, dry holes and leasehold  equipment, are capitalized.
  Net capitalized costs are  limited to the estimated  future net
  revenues,  discounted  at  10%  per  annum,  from  proved  oil,
  natural  gas   and  natural   gas  liquids   reserves.     Such
  limitations  are imposed  separately for  Devon's  oil and  gas
  properties in  the United States and Canada.  Capitalized costs
  are  depleted  by  an  equivalent   unit-of-production  method,
  converting gas and natural  gas liquids to oil at the  ratio of
  one barrel ("Bbl") of oil to six thousand cubic
  feet  ("Mcf") of  natural  gas  and one  barrel  of oil  to  42
  gallons of natural gas liquids.  No gain or  loss is recognized
  upon disposal  of oil and gas  properties unless  such disposal
  significantly  alters  the  relationship  between   capitalized
  costs and proved reserves.

               Devon  adopted the  provisions  of  SFAS No.  121,
  "Accounting for  the Impairment  of Long-Lived  Assets and  for
  Long-Lived  Assets to  be  Disposed Of,"  on January  1,  1996.
  SFAS  No.  121  requires that  long-lived  assets  and  certain
  identifiable intangibles  be reviewed  for impairment  whenever
  events or changes  in circumstances indicate that the  carrying
  amount of an asset may  not be recoverable.  Due to Devon's use
  of  the full  cost  method of  accounting for  its oil  and gas
  properties, SFAS  No. 121 does not apply to Devon's oil and gas
  property  assets which  comprise approximately  97% of  Devon's
  net property and equipment.   Accordingly, the adoption of SFAS
  No. 121  did not have an  impact on  Devon's financial position
  or results of operations in 1996.

               Depreciation  and  amortization of  other property
  and equipment,  including leasehold  improvements, are provided
  using the straight-line method based on  estimated useful lives
  from 3 to 39 years.

  Deferred Revenue

               Deferred  revenue  at  the end  of  1996  consists
  primarily of the  unrecognized gain from the  termination of an
  interest  rate  swap  agreement.    In  prior  years,  deferred
  revenue  included  primarily  funds received  under take-or-pay
  provisions  of  certain  gas  contracts,  which   provided  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

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

  Major Purchasers

               During  1996,  there  was  one  purchaser,  Aquila
  Energy  Marketing  Corporation  ("Aquila"),  who accounted  for
  over 10%  of Devon's  gas sales.  Aquila accounted  for 45%  of
  Devon's  1996   gas  sales.    During   1995,  there  were  two
  purchasers who accounted  for over  10% of  Devon's gas  sales.
  These two purchasers  and their respective share  of gas  sales
  were: Aquila - 31%; and  Enron Gas Marketing, Inc.  ("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. - 18%.

  Income Taxes

               Devon accounts  for income  taxes using  the asset
  and  liability  method,   whereby  deferred   tax  assets   and
  liabilities  are recognized  for  the future  tax  consequences
  attributable  to differences  between  the  financial statement
  carrying   amounts   of  assets   and  liabilities   and  their
  respective tax  bases, as well  as the future tax  consequences
  attributable  to   the  future  utilization   of  existing  net
  operating  loss and other types of carryforwards.  Deferred tax
  assets and  liabilities are  measured using  enacted tax  rates
  expected  to apply  to  taxable income  in  the years  in which
  those temporary differences and  carryforwards are expected  to
  be  recovered or  settled.  The  effect on  deferred tax assets
  and  liabilities of  a  change in  tax  rates is  recognized in
  income in the period that includes the enactment date.

  General and Administrative Expenses

               General and administrative  expenses are  reported
  net of amounts allocated  to working interest owners of the oil
  and gas  properties operated by Devon,  net of  amounts charged
  to  affiliated  partnerships  for  administrative and  overhead
  costs,  and  net of  amounts capitalized  pursuant to  the full
  cost method of accounting.

  Net Earnings Per Common Share

               Net earnings per common share assuming no dilution
  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, and the  Trust Convertible Preferred Securities  issued
  in 1996 are excluded as they are not common stock equivalents.

               For 1996, net  earnings per common  share assuming
  full  dilution  is  based  upon  the  adjusted  amount  of  net
  earnings and the  adjusted number of common shares  outstanding
  assuming the  Trust Convertible  Preferred Securities  had been
  converted  to common  stock as of  their issuance  date in July
  1996.    The  fully  diluted  per  share  amount  in  1996 also
  includes the  effect of  Devon's outstanding  stock options  as
  calculated  using the treasury stock method.  The 1996 adjusted
  net earnings used for  the fully diluted calculation  was $37.8
  million,  and  the   adjusted  number  of  common  shares   was
  24,860,910.

               No fully  diluted per share  amounts are presented
  for 1995 and 1994 due  to the insignificant dilutive  effect of
  the stock options outstanding.

  Dividends

               Dividends on common stock  were paid in 1994, 1995
  and the  first three quarters  of 1996 at a  per share rate  of
  $0.03 per  quarter.  The dividend  rate was  increased to $0.05
  per share for the fourth quarter of 1996.

  Fair Value of Financial Instruments

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

  Statements of Cash Flows

               For purposes  of  the consolidated  statements  of
  cash flows, Devon considers all highly  liquid investments with
  original  maturities  of  three  months  or  less  to  be  cash
  equivalents. 

  Commitments and Contingencies

               Liabilities  for  loss contingencies  arising from
  claims, assessments, litigation or  other sources are  recorded
  when it is probable that  a liability has been incurred and the
  amount can be reasonably estimated.

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

  2.           Acquisitions and Pro Forma Information

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

               Devon   recorded   the   KMG-NAOS  Properties   at
  approximately  $221.6 million.   Such  value was  based on  the
  value of the shares  of Devon common stock issued as determined
  pursuant  to  generally accepted  accounting  principles.    An
  additional  $28.0  million   was  allocated  to   the  KMG-NAOS
  Properties  for the deferred income tax  liability created as a
  result of the substantially tax-free nature  of the transaction
  to   Kerr-McGee.     Excluding  the   additional  deferred  tax
  liability,  the  amount recorded  for  the  KMG-NAOS Properties
  includes approximately  $191.7 million allocated  to proved oil
  and  gas  reserves,  $29.0  million  allocated  to  undeveloped
  leasehold  acquired and $0.9  million allocated  to inventories
  and  other assets  acquired.   Including  the additional  $28.0
  million  of   deferred  tax  liability,   $214.2  million   was
  allocated to proved  reserves and $34.5 million to  undeveloped
  leasehold.

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

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

               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 "Alta  Merger").
  The Alta 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
  Alta  Merger.   Subsequently,  in  February 1995,  former  Alta
  stockholders  received  an  additional  cash  payment  of  $2.4
  million based upon  the post-closing evaluation of the  Camille
  Adams #1 well in  Louisiana.  Devon also incurred $41.4 million
  of  other costs  related  to the  Alta  Merger.   This included
  $31.7 million to  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  Alta
  Merger.

               Devon recorded additional deferred tax liabilities
  of $11.5  million due  to the substantially  tax-free nature of
  the Alta  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  Alta 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.   The
  Alta  Merger was  accounted  for  by  the  purchase  method  of
  accounting  for   business  combinations.    Accordingly,   the
  accompanying  1994  consolidated  statement of  operations does
  not include  any revenue or expenses associated with Alta prior
  to the May 18, 1994 closing date.

  Pro Forma Information (Unaudited)

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

                                                              1996

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

                    Total revenues                         297,184,000

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

                    Total costs and expenses               180,992,000

               Earnings before income taxes                116,192,000

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

                    Total income tax expense                46,744,000

               Net earnings                               $ 69,448,000

               Net earnings per average common
                share outstanding:
                 Assuming no dilution                            $2.16
                 Assuming full dilution                          $2.08

               Weighted average common shares outstanding   32,086,310

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

</TABLE>

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

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

  3.           San Juan Basin Transaction

               Effective January  1, 1995, Devon and an unrelated
  company entered  into a transaction  covering substantially all
  of Devon's  San Juan Basin coal  seam gas  properties (the "San
  Juan  Basin Transaction").    These  coal seam  gas  properties
  represented Devon's largest oil  and gas reserve position as of
  December 31,  1994.  The  properties' estimated reserves as  of
  year-end 
  1994 were 199.2 billion cubic  feet ("Bcf") of natural  gas, or
  31%  of  Devon's  633.2  equivalent  Bcf  of  combined  oil and
  natural  gas  reserves.   In  addition  to  the  cash flow  and
  earnings impact
  normally  associated  with   oil  and  gas  production,   these
  properties  also qualify  as  a  "nonconventional fuel  source"
  under  the Internal Revenue  Code of  1986.   Consequently, gas
  produced from these properties through the  year 2002 qualifies
  for Section  29 tax  credits, which  as of  year-end 1996  were
  equal to approximately $1.02 per million Btu ("MMBtu").

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

               The production  payment retained by Devon is equal
  to 94.05%  of the  first 143.4  Bcf  of gas  produced from  the
  properties, or 134.9 Bcf.   As such, Devon continues  to record
  gas sales and associated production and  operating expenses and
  reserves associated  with the  production payment.   Production
  from the retained production payment is  currently estimated to
  occur over a period of 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 
  years  ended December  31, 1996 and  1995, Devon received $11.5
  million  and   $13.9  million,  respectively,  related  to  the
  credits.  Of  these amounts,  $10.3 million  and $12.8  million
  were
  recorded   as  additional   gas  sales   in   1996  and   1995,
  respectively, and $1.2  million and $1.1 million were  recorded
  as an addition  to liabilities in 1996  and 1995, respectively,
  as  discussed  in  the  following  paragraph.    Based  on  the
  reserves estimated at December 31, 1996, and  an assumed annual
  inflation factor of 2%,  Devon estimates it will receive  total
  tax  credit payments  of approximately  $58  million from  1997
  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 years ended  December 31,
  1996 and 1995, $1.2 million and $1.1 million,  respectively, of
  the total amount  received for  tax credit payments  were added
  to  the liability, which raised  the liability  balance to $7.9
  million as of December 31, 1996.

               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   $7.9  million  of   other
  liabilities  recorded as of year-end 1996, does not include any
  amount related to such reserves.

  4.           Supplemental Cash Flow Information

               Cash payments for interest in 1996, 1995, and 1994
  were   approximately  $5.5  million,  $6.7   million  and  $5.1
  million, respectively.   Cash  payments for  federal and  state
  income  taxes in  1996, 1995, and  1994 were approximately $3.4
  million, $2.2 million and $1.8 million, respectively.

               The  1996 acquisition  of the  KMG-NAOS Properties
  and  the   1994  Alta   Merger  involved   cash  and   non-cash
  consideration as presented below:
<TABLE>
<CAPTION>
                                                                
                                                1996                      1994

      <S>                                  <C>                        <C>
      Cash payments made                   $          -               42,915,845
      Value of common stock issued          221,576,040               21,991,084
      Liabilities assumed                             -                7,192,671
      Deferred tax liability created         28,029,000               11,500,000

      Fair value of assets acquired        $249,605,040               83,599,600

</TABLE>
               The above  cash payments of $42.9  million in 1994
  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 Alta Merger.

  5.           Accounts Receivable

               The components of accounts receivable included the
  following:
<TABLE>
<CAPTION>
                                                     December 31,
                                            1996         1995            1994

     Oil, gas and natural gas liquids
       <S>                              <C>            <C>           <C>
       revenue accruals                 $24,200,047    11,169,313    10,973,589
     Joint interest billings              4,318,764     2,962,037     3,367,493
     Income tax refunds due                       -             -       959,085
     Other                                1,461,495       493,945       551,632

                                         29,980,306    14,625,295    15,851,799
     Allowance for doubtful accounts       (400,000)     (225,000)     (225,000)

     Net accounts receivable            $29,580,306    14,400,295    15,626,799
</TABLE>

  6.      Property and Equipment

     Property and equipment included the following:
<TABLE>
<CAPTION>
                                                                  December 31,
                                                      1996            1995            1994
     Oil and gas properties:
          <S>                                     <C>             <C>            <C>
          Subject to amortization                 $899,827,749    604,227,702    503,174,488
          Not subject to amortization:
               Acquired in 1996                     35,141,800              -              -
               Acquired in 1995                      5,034,942      5,635,170              -
               Acquired in 1994                      1,001,291      1,001,427      1,451,109
               Acquired in 1993                      5,204,995      5,556,977      5,556,977
               Acquired in 1992                      8,113,899      8,257,985      8,561,031

          Accumulated depreciation, depletion
               and amortization                   (278,923,340)  (237,385,785)  (200,746,032)

                 Net oil and gas properties        675,401,336    387,293,476    317,997,573

     Other property and equipment                   20,481,080      6,758,643      5,197,536

     Accumulated depreciation and amortization      (3,036,070)    (2,233,382)    (1,888,929)

                 Net other property and equipment   17,445,010      4,525,261      3,308,607

     Property and equipment, net of
          accumulated depreciation,
          depletion and amortization             $ 692,846,346    391,818,737    321,306,180
</TABLE>
     Depreciation, depletion and  amortization expense  consisted
  of the following components:
<TABLE>
<CAPTION>
                                                            Year Ended December 31,
                                                       1996            1995          1994
     <S>                                           <C>             <C>            <C>

     Depreciation, depletion and amortization
       of oil and gas properties                   $41,537,555     36,639,753     32,861,174
     Depreciation and amortization of other
       property and equipment                        1,337,420      1,045,978        865,092
     Amortization of other assets                      486,054        404,052        405,884

          Total expense                            $43,361,029     38,089,783     34,132,150
</TABLE>

  7.      Long-term Debt

     Devon has long-term lines of credit pursuant to which it can
  borrow up to an amount  determined by the banks based  on their
  evaluation of the  assets and cash flow (the  "Borrowing Base")
  of Devon. The established Borrowing Base at December 31,  1996,
  was $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.   The average interest rates on the outstanding
  debt at the end of 1996, 1995  and 1994, were 6.19%, 6.64%  and
  6.83%, respectively.   The loan agreements also  provide for  a
  quarterly facility fee equal to .25% per annum.

     Debt  borrowed  under the  credit  lines is  unsecured.   No
  principal payments  are  required  until  maturity  unless  the
  unpaid balance  exceeds the maximum  loan amount.  The  maximum
  loan  amount is  equal to the  Borrowing Base  until August 31,
  1999.  Thereafter, the maximum  loan amount will be  reduced by
  8.33%  every three  months  until August  31,  2002.   The loan
  agreements contain  certain covenants  and restrictions,  among
  which  are  limitations  on additional  borrowings  and  annual
  sales  of  properties  valued at  more  than  $25 million,  and
  working capital  and net  worth maintenance  requirements.   At
  December 31, 1996, Devon  was in compliance with such covenants
  and restrictions.

     On December  31, 1996, Devon established  a demand revolving
  operating credit facility  with a Canadian bank.  This facility
  is  unsecured  and  will  be  utilized  for  general  corporate
  purposes  related to  Devon's  new  Canadian operations.    The
  credit  line  totals   $12.5  million  Canadian  dollars,   and
  interest  is charged  at  the bank's  prime  rate for  loans to
  Canadian  customers.    Amounts borrowed  are  due  on  demand.
  However, due  to Devon's  sources of  long-term debt  described
  above, amounts  borrowed pursuant to  the Canadian credit  line
  are expected  to be classified as  long-term debt.   No amounts
  were  borrowed against  the Canadian  credit  line at  year-end
  1996.

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

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

  8.      Income Taxes

     At December 31, 1996,  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              1998 - 2008      $14,100,000
     Net operating loss - various states       1997 - 2010      $10,000,000
     Statutory depletion                       No expiration    $ 1,200,000
     Minimum tax credit                        No expiration    $ 5,600,000
</TABLE>
     All  of  the  carryforward  amounts shown  above  have  been
  utilized for financial purposes to reduce deferred taxes.

     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,
                                               1996       1995      1994
     <S>                                        <C>        <C>       <C>

     Federal statutory tax rate                 35%        35%       35%
     Nonconventional fuel source credits         -         (1)        -
     State income taxes                          5          4         3
     Effect of San Juan Basin Transaction        2          4         -
     Other                                      (1)         1        (2)
     Effective income tax rate                  41%        43%       36%  
</TABLE>

     The  tax effects of temporary differences  that gave rise to
  significant   portions   of   the  deferred   tax   assets  and
  liabilities  at December 31, 1996, 1995  and 1994 are presented
  below:
<TABLE>
<CAPTION>
                                                                            December 31,
                                                                   1996         1995         1994

     Deferred tax assets:
          <S>                                                <C>             <C>         <C>
          Net operating loss carryforwards                   $   5,314,000   6,082,000   6,127,000
          Statutory depletion carryforwards                        412,000   2,287,000   3,087,000
          Investment tax credit carryforwards                       42,000      85,000     813,000
          Minimum tax credit carryforwards                       5,624,000   5,576,000   2,195,000
          Production payments                                   19,685,000  24,770,000           -
          Other                                                  2,613,000   1,966,000     897,000

               Total gross deferred tax assets                  33,690,000  40,766,000  13,119,000
               Less valuation allowance                            100,000     100,000     100,000

               Net deferred tax assets                          33,590,000  40,666,000  13,019,000
     Deferred tax liabilities:
          Property and equipment, principally due
               to differences in depreciation, and
               the expensing of intangible drilling
               costs for tax purposes                         (113,111,000) (74,369,000) (40,097,000)

                 Net deferred tax liability                  $ (79,521,000) (33,703,000) (27,078,000)
</TABLE>
     As shown in the  above schedule, Devon has recognized  $33.6
  million  of net  deferred tax assets  as of  December 31, 1996.
  Such  amount  consists  almost entirely  of  $11.4  million  of
  various carryforwards available  to offset future income taxes,
  and  $19.7 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, and  the  statutory
  depletion and  minimum tax credit  carryforwards which have  no
  expiration  dates.    The tax  benefits  of  carryforwards  are
  recorded  as an  asset to  the extent that  management assesses
  the utilization  of such carryforwards to  be "more likely than
  not."   When  the  future utilization  of  some portion  of the
  carryforwards  is determined not to be  "more likely than not",
  a valuation  allowance is provided  to reduce the recorded  tax
  benefits from such assets.

     Devon expects the tax  benefits from the net operating  loss
  carryforwards  to be  utilized  between 1997  and 1999.    Such
  expectation is based  upon current estimates of taxable  income
  during  this  period,  considering limitations  on  the  annual
  utilization of these benefits as set forth
  by  federal  tax  regulations.   Significant  changes  in  such
  estimates  caused  by  variables such  as  future  oil  and gas
  prices or  capital expenditures could  alter the timing of  the
  eventual utilization  of such  carryforwards.  There  can be no
  assurance  that  Devon  will generate  any  specific  level  of
  continuing  taxable  earnings.   However,  management  believes
  that Devon's  future taxable income  will more likely than  not
  be  sufficient   to   utilize   substantially   all   its   tax
  carryforwards prior to their expiration.   A $100,000 valuation
  allowance  has been recorded at  December 31,  1996, related to
  depletion carryforwards acquired in the Alta Merger.

     The  $19.7  million  of   deferred  tax  assets  related  to
  production payments is offset  by a portion of the deferred tax
  liability related  to the  excess financial  basis of  property
  and equipment.   The  income tax  accounting for  the San  Juan
  Basin  Transaction  described  in  Note  3   differs  from  the
  financial  accounting  treatment  which  is  described in  such
  note.  For income tax purposes,  a gain from the conveyance  of
  the  properties  was realized,  and the  present  value  of the
  production  payments to  be  received was  recorded as  a  note
  receivable.   For  presentation  purposes,  the  $19.7  million
  represents the tax  effect of the difference  in accounting for
  the  production payment, less  the effect  of the  taxable gain
  from the transaction which is being deferred  and recognized on
  the installment basis for income tax purposes.

  9.      Trust Convertible Preferred Securities

     On July 10, 1996,  Devon, through its newly-formed affiliate
  Devon  Financing  Trust,  completed  the   issuance  of  $149.5
  million  of 6.5%  trust  convertible preferred  securities (the
  "TCP  Securities") in  a private  placement.   Devon  Financing
  Trust issued 2,990,000 shares  of the TCP Securities at $50 per
  share.    Each TCP  Security  is  convertible at  the  holder's
  option  into 1.6393 shares of Devon common stock, which equates
  to  a conversion  price  of $30.50  per  share of  Devon common
  stock.

     Devon  Financing  Trust  invested   the  $149.5  million  of
  proceeds  in 6.5%  convertible  junior  subordinated debentures
  issued  by Devon  (the  "Convertible  Debentures").   In  turn,
  Devon  used  the   net  proceeds  from  the  issuance   of  the
  Convertible Debentures  to  retire debt  outstanding under  its
  credit lines.

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

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

     Devon  owns all  the  common securities  of Devon  Financing
  Trust.   As such,  the accounts  of Devon  Financing Trust  are
  included  in Devon's  consolidated financial  statements  after
  appropriate  eliminations   of  intercompany   balances.    The
  distributions on the  TCP Securities are recorded  as a  charge
  to  pre-tax  earnings  on Devon's  consolidated  statements  of
  operations, and such distributions are deductible  by Devon for
  income tax purposes.

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

  10.     Stockholders' Equity

     The  authorized  capital  stock  of Devon  consists  of  400
  million shares of common stock,  par value $.10 per  share (the
  "Common Stock"), and  three million shares of preferred  stock,
  par  value  $1.00  per  share  (the  "Preferred Stock").    The
  Preferred Stock may  be issued in one  or more series, and  the
  terms and rights of such stock will be determined  by the Board
  of Directors.

     Devon's Board of Directors  has designated 150,000 shares of
  the Preferred Stock as Series A  Junior Participating Preferred
  Stock (the "Series  A Preferred Stock") in connection  with the
  adoption  of  the share  rights  plan described  later in  this
  note.  At December  31, 1996, there were no shares of  Series A
  Preferred Stock issued  or outstanding.  The Series A Preferred
  Stock  is entitled  to receive  cumulative quarterly  dividends
  per  share  equal to  the  greater  of  $10 or  100  times  the
  aggregate  per share amount of  all dividends (other than stock
  dividends) declared  on  Common  Stock  since  the  immediately
  preceding quarterly dividend  payment date or, with respect  to
  the first  payment date, since the  first issuance  of Series A
  Preferred Stock.  Holders of the
  Series A  Preferred Stock are entitled  to 100  votes per share
  (subject  to adjustment  to prevent  dilution)  on all  matters
  submitted  to  a  vote  of  the  stockholders.    The  Series A
  Preferred Stock  is neither  redeemable nor  convertible.   The
  Series A  Preferred Stock ranks prior  to the  Common Stock but
  junior to all other classes of Preferred Stock.

  Stock Option Plans

     Devon has outstanding stock options issued to key management
  and   professional  employees  under  two  stock  option  plans
  adopted  in  1988 and  1993  ("the  1988  Plan"  and "the  1993
  Plan").     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,
  1996,  15  participants  held the  303,400  options outstanding
  under the 1988 Plan.

     Effective  June 7,  1993, Devon  adopted  the 1993  Plan and
  reserved  one  million  shares of  Common  Stock  for  issuance
  thereunder.  Twenty-two employees were eligible  to participate
  in the 1993 Plan at year-end 1996.

     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,
  1996, 23  participants  held  the 898,600  options  outstanding
  under the 1993 Plan.   There were 88,700 options  available for
  future grants as of December 31, 1996.

     A summary of  the status of Devon's stock option plans as of
  December 31,  1994, 1995 and 1996,  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, 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

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

  Balance at December 31, 1996      1,202,000   $23.299     823,500     $21.783
</TABLE>
          The weighted  average fair  values  of options  granted
  during 1996 and 1995  were $12.97 and $9.89, respectively.  The
  fair value  of each option  grant was estimated for  disclosure
  purposes only  on the date of  grant using  the Binomial Option
  Pricing  Model with  the  following  assumptions for  1996  and
  1995, respectively: risk-free interest rates of  6.3% and 5.5%;
  dividend yields  of 0.6% and  0.5%; expected lives  of 5  and 5
  years; and  volatility of  the price of  the underlying  common
  stock of 33.9% and 38.1%.

     The  following table  summarizes  information about  Devon's
  stock  options which  were outstanding,  and  those which  were
  exercisable, as of December 31, 1996:
<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-$14       108,600      4.6 years      $9.662       108,600       $9.662
  $18-$21      205,700      7.9 years     $18.088       146,400      $18.092
  $23-$26      644,200      7.7 years     $23.784       487,800      $23.816
  $32-$33      243,500     10.0 years     $32.500        80,700      $32.500

             1,202,000      7.9 years     $23.299       823,500      $21.783
</TABLE>

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

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

          Net earnings per share:
               As reported:
                    Assuming no dilution          $1.57           0.66
                    Assuming full dilution        $1.52           0.66
               Pro forma:
                    Assuming no dilution          $1.54           0.61
                    Assuming full dilution        $1.49           0.61
</TABLE>

  Share Rights Plan

     Under Devon's share rights plan, stockholders have one right
  for  each  share of  Common  Stock  held.    The rights  become
  exercisable  and  separately  transferable  ten  business  days
  after a)  an  announcement  that  a  person  has  acquired,  or
  obtained the  right  to acquire,  15%  or  more of  the  voting
  shares outstanding, or b) commencement of a tender  or exchange
  offer that could result  in a person owning 15% or more  of the
  voting shares outstanding.

     Each right entitles its  holder (except a holder who  is the
  acquiring  person) to  purchase either a)  1/100 of  a share of
  Series A Preferred  Stock for $75.00, subject  to adjustment or
  b) Devon Common Stock with a value equal  to twice the exercise
  price of the right, subject to adjustment  to prevent dilution.
  In the event of  certain merger or asset sale transactions with
  another party or  transactions which would increase the  equity
  ownership of  a  shareholder who  then  owned  15% or  more  of
  Devon, each  Devon right will  entitle its  holder to  purchase
  securities  of the  merging  or acquiring  party with  a  value
  equal to twice the exercise price of the right.

     The  rights, which have no voting power, expire on April 16,
  2005.  The rights may be redeemed  by Devon for $.01 per  right
  until the rights become exercisable.

  11.     Retirement Plans

     Devon  has a  defined  benefit retirement  plan (the  "Basic
  Plan")  which   is  non-contributory   and  includes  employees
  meeting certain  age and  service requirements.   The  benefits
  are based on the  employee's years of service and compensation.
  Devon's funding  policy is to  contribute annually the  maximum
  amount  that can  be deducted for  federal income tax purposes.
  Rights  to amend  or terminate the  Basic Plan  are retained by
  Devon.

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

     The following  table sets forth the  aggregate funded status
  of the  Basic Plan and  related amounts  recognized in  Devon's
  balance sheets:
<TABLE>
<CAPTION>
                                                        December 31,
                                                1996         1995           1994

     Actuarial present value of benefit
       obligations:
          Accumulated benefit obligation:
            <S>                             <C>           <C>           <C>
            Vested                          $(3,619,000)  (3,500,000)   (2,648,000)
            Nonvested                          (741,000)    (654,000)     (282,000)

            Total                           $(4,360,000)  (4,154,000)   (2,930,000)

          Projected benefit obligation for
             service rendered to date        (5,122,000)  (4,782,000)   (3,378,000)
     Plan assets at fair value, primarily
       investments in mutual funds            5,022,000    4,227,000     3,252,000

     Plan assets less than projected benefit
       obligation                              (100,000)    (555,000)     (126,000)
     Unrecognized prior service cost (benefit) (131,000)    (154,000)     (176,000)
     Unrecognized net loss from past experience
       different from that assumed, and effects
       of changes in assumptions                519,000      921,000       225,000

     Prepaid (accrued) pension expense     $    288,000      212,000       (77,000)
</TABLE>

            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,  1996
  and 1995:
<TABLE>
<CAPTION>
                                                               December 31,   
                                                            1996           1995
     Actuarial present value of benefit obligations:
          Accumulated benefit obligation:
            <S>                                         <C>           <C>
            Vested                                      $(1,960,000)  (1,658,000)
            Nonvested                                      (279,000)    (255,000)

            Total                                       $(2,239,000)  (1,913,000)

          Projected benefit obligation for service
            rendered to date                             (2,907,000)  (2,245,000)
     Plan assets at fair value                                    -            -

     Plan assets less than projected benefit obligation  (2,907,000)  (2,245,000)
     Unrecognized prior service cost                      1,235,000    1,354,000
     Unrecognized net loss from past experience different
          from that assumed, and effects of changes in
          assumptions                                       446,000      185,000

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

     Total pension liability                            $(2,239,000)  (1,913,000)
</TABLE>

            The  $2.2  million  and  $1.9  million  total pension
  liability  of the Supplementary  Plan as  of December  31, 1996
  and  1995,  respectively,   are  included  in  long-term  other
  liabilities on  the accompanying  consolidated balance  sheets.
  The additional  minimum liabilities  of $1.0  million and  $1.2
  million at year-end  1996 and 1995, respectively, are offset by
  intangible assets of $1.0 million  in 1996 and $1.2  million in
  1995.  These intangible  assets are included in other assets on
  the balance sheets.

            Net pension  expense for Devon's  two defined benefit
  plans included the following components:
<TABLE>
<CAPTION>
                                                                Year Ended December 31,
                                                                1996       1995     1994 

     <S>                                                     <C>         <C>      <C>
     Service cost - benefits earned during the period        $ 557,000   362,000  277,000
     Interest cost on projected benefit obligation             569,000   446,000  284,000
     Actual return on plan assets                             (453,000) (536,000) (20,000)
     Net amortization and deferral                             231,000   345,000 (231,000)

     Net periodic pension expense                            $ 904,000   617,000  310,000
</TABLE>

     The weighted  average discount rate used  in determining the
  actuarial present value of the projected  benefit obligation in
  1996, 1995  and 1994  was 7.5%, 7.25%  and 8.5%,  respectively.
  The rate of increase in  future compensation levels was  5% for
  all three  years.   The expected  long-term rate  of return  on
  assets  was  8.5%,  8.5%   and  8%  in  1996,  1995  and  1994,
  respectively.

     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
  $188,000, $170,000  and $158,000 for  the years ended  December
  31, 1996, 1995 and 1994, respectively.

  12.     Commitments and Contingencies

     Devon is  party  to various  legal  actions arising  in  the
  normal  course  of  business.   Matters  that  are  probable of
  unfavorable  outcome  to  Devon and  which  can  be  reasonably
  estimated are accrued.  Such accruals are based on  information
  known about the  matters, Devon's estimates of  the outcomes of
  such matters and  its experience in contesting, litigating  and
  settling similar matters.   None of the actions are believed by
  management to  involve future  amounts that  would be  material
  after consideration of recorded accruals.

     The 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  1996, and for
  future years as well.  In early 1997, the  MMS asserted a claim
  for  additional  royalties.   While  the  specific  claim  only
  covers 17 months of  the seven-year period in question, the MMS
  has requested Devon  to calculate and pay additional  royalties
  for the entire  seven-year period using methods and  procedures
  consistent with the calculation for  the 17 months.   Devon has
  not  determined  whether   it  agrees  with  the  methods   and
  procedures used  by the  MMS  in  its calculations,  and  Devon
  intends  to   vigorously  contest   any  claim  for   excessive
  additional  federal royalties  through available administrative
  and  judicial  processes.    However,  Devon   has  accrued  an
  estimate of additional  federal royalties related to its  share
  of gas  produced from 1990 through  1996.   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 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.

     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  these  assessments  in  January  1996,  as  well   as  an
  additional  $0.2 million for 1996 taxes which were paid monthly
  throughout the  year, 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.  Devon has not expensed in  its financial statements the
  taxes,  penalties and interest paid,  but rather  has recorded
  the $1.1  million total as a receivable.

     The following is a schedule by year of future minimum rental
  payments required under  operating leases that have initial  or
  remaining noncancelable  lease terms in excess  of one  year as
  of December 31, 1996:
<TABLE>
<CAPTION>
          Year ending December 31,
              <C>                       <C>
              1997                      $233,000
              1998                       183,000
              1999                       138,000
              2000                       123,000

Total minimum lease payments required   $677,000
</TABLE>

     Total rental expense for all  operating leases is as follows
  for the years ended December 31:
<TABLE>
              <C>     <C>
              1996    $572,177
              1995    $546,388
              1994    $521,769
</TABLE>

  13.     Oil and Gas Operations

  Costs Incurred

     The following tables  reflect the costs incurred  in oil and
  gas   property   acquisition,  exploration,   and   development
  activities:
<TABLE>
<CAPTION>
                                                                           Total
                                                                   Year Ended December 31, 
                                                               1996          1995         1994   
     Property acquisition costs:
          Proved, excluding deferred income
            <S>                                            <C>            <C>          <C>
            taxes                                          $199,655,000   47,316,000   70,376,000
          Deferred income taxes                              22,557,000            -   11,500,000

          Total proved, including deferred income taxes    $222,212,000   47,316,000   81,876,000

          Unproved, excluding deferred income taxes         $29,673,000    4,529,000    1,797,000
          Deferred income taxes                               5,472,000            -            -

          Total unproved, including deferred income taxes    35,145,000    4,529,000    1,797,000

     Exploration costs                                     $  2,708,000    7,174,000    5,194,000
     Development costs                                     $ 73,468,000   56,253,000   26,268,000

<CAPTION>
                                                                         Domestic                 
                                                                   Year Ended December 31,
                                                               1996          1995         1994
     Property acquisition costs:
          Proved, excluding deferred income
            taxes                                          $150,546,000   47,316,000   70,376,000
          Deferred income taxes                              15,257,000            -   11,500,000

          Total proved, including deferred income taxes    $165,803,000   47,316,000   81,876,000

          Unproved, excluding deferred income taxes         $26,073,000    4,529,000    1,797,000
          Deferred income taxes                               5,472,000            -            -

          Total unproved, including deferred income taxes    31,545,000    4,529,000    1,797,000

     Exploration costs                                     $  2,708,000    7,174,000    5,194,000 
     Development costs                                     $ 73,468,000   56,253,000   26,268,000

<CAPTION>
                                                                            Canada                 
                                                                   Year Ended December 31,
                                                              1996             1995          1994   
     Property acquisition costs:
          Proved, excluding deferred income
            taxes                                         $ 49,109,000             -            -
          Deferred income taxes                              7,300,000             -            -

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

          Unproved                                        $  3,600,000             -            -
     Exploration costs                                    $          -             -            -
     Development costs                                    $          -             -            -
</TABLE>

     Pursuant  to  the  full  cost method  of  accounting,  Devon
  capitalizes  certain of its general and administrative expenses
  which  are related  to  property acquisition,  exploration  and
  development activities.  Such  capitalized expenses, which  are
  included in  the costs  shown in  the above  tables, were  $2.9
  million, $2.7 million and  $2.3 million in the years 1996, 1995
  and 1994, respectively.

     Due to the substantially  tax-free nature of the acquisition
  of the KMG-NAOS properties  to Kerr-McGee, and of the 1994 Alta
  Merger  to  the  former   Alta  stockholders,  Devon   recorded
  additional  deferred tax  liabilities of  $28.0 million related
  to the  KMG-NAOS acquisition and $11.5  million related  to the
  Alta  Merger.  As  shown in the above  tables, the deferred tax
  liabilities  caused  an  additional  $22.5  million  and  $11.5
  million to  be allocated to proved oil and gas reserves in 1996
  and  1994, respectively, and an  additional $5.5  million to be
  allocated to unproved properties in 1996.

  Results of Operations for Oil and Gas Producing Activities

     The   following  tables   include   revenues  and   expenses
  associated  directly  with   Devon's  oil  and   gas  producing
  activities.    They do  not include  any allocation  of Devon's
  interest  costs or general  corporate overhead  and, therefore,
  are  not necessarily  indicative  of  the contribution  to  net
  earnings  of Devon's  oil  and  gas  operations.    Income  tax
  expense has  been calculated by  applying statutory income  tax
  rates to  oil and  gas sales  after deducting costs,  including
  depreciation,  depletion  and  amortization  and  after  giving
  effect  to permanent differences.   For  the three  year period
  ended  December 31,  1996, Devon had  no oil  and gas producing
  activities outside the United States.
<TABLE>
<CAPTION>
                                                            Year Ended December 31,
                                                         1996          1995         1994

     <S>                                            <C>             <C>           <C>
     Oil, gas and natural gas liquids sales         $162,558,000    112,425,000   99,366,000
     Production and operating expenses               (42,226,000)   (34,121,000) (31,421,000)
     Depreciation, depletion and amortization        (41,538,000)   (36,640,000) (32,861,000)
     Income tax expense                              (27,796,000)   (15,536,000) (12,411,000)

     Results of operations for oil and gas
          producing activities                      $ 50,998,000     26,128,000   22,673,000
     Depreciation, depletion and amortization
          per equivalent barrel of production              $3.88           3.65         3.45
</TABLE>

  14.     Supplemental Information on  Oil and Gas Operations (Unaudited)

     The following supplemental  unaudited information  regarding
  the oil  and gas activities of  Devon is  presented pursuant to
  the disclosure requirements  promulgated by the  Securities and
  Exchange  Commission  and  Statement  of  Financial  Accounting
  Standards  No. 69,  "Disclosures About  Oil  and Gas  Producing
  Activities".

  Quantities of Oil and Gas Reserves

     Set forth  below  is a  summary of  the changes  in the  net
  quantities of  crude oil, natural  gas and natural gas  liquids
  reserves for each of the  three years ended December  31, 1996.
  Approximately  94%, 92%  and 91%,  of  the respective  year-end
  1996, 1995  and 1994 domestic  proved reserves were  calculated
  by the independent petroleum consultants LaRoche Petroleum 
  Consultants, Ltd.  The  remaining percentages  of domestic
  reserves  are based  on  Devon's  own  estimates.    All  of
  the 1996  Canadian  proved  reserves   were   calculated   by
  the   independent  petroleum  consultants AMH Group Ltd.

<TABLE>
<CAPTION>
                                                                Total             
                                                                           Natural
                                                  Oil          Gas        Gas Liquids
                                                 (Bbls)       (Mcf)         (Bbls)   

  <S>                                          <C>         <C>            <C>
  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
     Revisions of estimates                     2,365,000    4,359,000    1,096,000
     Extensions and discoveries                 3,680,000   14,849,000      852,000
     Purchase of reserves                      21,189,000  249,922,000    2,130,000
     Production                               (3,816,000)  (35,714,000)    (952,000)
     Sale of reserves                           (403,000)   (1,743,000)     (16,000)

  Proved reserves as of December 31, 1996     67,481,000   595,519,000   12,579,000
  Proved developed reserves as of:
     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
     December 31, 1996                        60,202,000   570,265,000   11,212,000

<CAPTION>
                                                             Domestic                      
                                                                            Natural
                                                 Oil           Gas        Gas Liquids
                                                (Bbls)        (Mcf)         (Bbls)   

  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
     Revisions of estimates                    2,365,000     4,359,000    1,096,000
     Extensions and discoveries                3,680,000    14,849,000      852,000
     Purchase of reserves                     13,659,000   209,064,000    1,246,000
     Production                               (3,816,000)  (35,714,000)    (952,000)
     Sale of reserves                           (403,000)   (1,743,000)     (16,000)

  Proved reserves as of December 31, 1996     59,951,000   554,661,000   11,695,000
  Proved developed reserves as of:
     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
     December 31, 1996                        52,672,000   529,407,000   10,328,000

<CAPTION>
                                                              Canada
                                                                            Natural
                                                 Oil           Gas        Gas Liquids
                                                (Bbls)        (Mcf)          (Bbls)


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

  Proved reserves as of December 31, 1996      7,530,000   40,858,000       884,000
  Proved developed reserves as of
    December 31, 1996                          7,530,000   40,858,000       884,000
</TABLE>

  Standardized Measure of Discounted Future Net Cash Flows

     The accompanying tables reflect the standardized measure  of
  discounted future net  cash flows relating to Devon's  interest
  in proved reserves:
<TABLE>
<CAPTION>
                                                          Total
                                                       December 31,
                                         1996              1995               1994

     <S>                           <C>                 <C>                <C>
     Future cash inflows           $ 3,989,582,000     1,476,418,000      1,186,845,000
     Future costs:
          Development                  (54,133,000)      (52,327,000)       (75,115,000)
          Production                (1,071,913,000)     (496,279,000)      (400,676,000)
     Future income tax expense        (785,702,000)     (153,431,000)       (71,427,000)

     Future net cash flows           2,077,834,000       774,381,000        639,627,000
     10% discount to reflect timing
          of cash flows               (901,617,000)     (328,481,000)      (281,421,000)

     Standardized measure of
          discounted future net
          cash flows               $ 1,176,217,000       445,900,000        358,206,000

     Discounted future net cash
          flows before income
          taxes                    $ 1,621,992,000       534,248,000        398,206,000

<CAPTION>
                                                         Domestic
                                                        December 31,
                                         1996               1995              1994

     Future cash inflows           $ 3,712,956,000     1,476,418,000      1,186,845,000
     Future costs:
          Development                  (54,064,000)      (52,327,000)       (75,115,000)
          Production                (1,013,750,000)     (496,279,000)      (400,676,000)
     Future income tax expense        (713,182,000)     (153,431,000)       (71,427,000)

     Future net cash flows           1,931,960,000       774,381,000        639,627,000
     10% discount to reflect timing of
          cash flows                  (846,174,000)     (328,481,000)      (281,421,000)

     Standardized measure of
          discounted future net
          cash flows               $ 1,085,786,000       445,900,000        358,206,000

     Discounted future net cash
          flows before income
          taxes                    $ 1,486,603,000       534,248,000        398,206,000

<CAPTION>
                                                            Canada 
                                                          December 31,
                                          1996                1995               1994

     Future cash inflows              $276,626,000                 -                  -
     Future costs:
          Development                      (69,000)                -                  -
          Production                   (58,163,000)                -                  -
     Future income tax expense         (72,520,000)                -                  -

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

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

     Discounted future net cash
          flows before income taxes   $135,389,000                 -                  -

</TABLE>

     Future cash inflows are computed by applying year-end prices
  (averaging   $24.52   per   barrel   of   oil,   adjusted   for
  transportation  and other  charges, $3.35  per Mcf  of gas  and
  $23.34 per barrel of  natural gas liquids at December 31, 1996)
  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 $3.35 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  total and  domestic cash  inflows
  shown in  the  tables above  include $48.7  million related  to
  these tax credit payments  from 1997 through 2002.  This amount
  has  been calculated  using the  assumption  that the  year-end
  1996 tax credit rate of $1.02 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 Transaction  as described  in  Note  3, the  future
  income tax expenses  estimated at December  31, 1994  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  that undiscounted amounts  of approximately $113
  million 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 at  year-end 1994.
  As  a result  of the San  Juan Basin Transaction, substantially
  all of the  value of  the Section  29 tax  credits at  year-end
  1996  and  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,
                                                      1996              1995            1994

          <S>                                     <C>               <C>             <C>
          Beginning balance                       $445,900,000      358,206,000     343,550,000
          Sales of oil, gas and natural gas
             liquids, net of production costs     (120,332,000)     (78,304,000)    (67,945,000)
          Net changes in prices and
             production costs                      519,456,000       60,498,000    (107,210,000)
          Extensions, discoveries, and improved
             recovery, net of future
             development costs                      42,522,000       22,308,000      14,629,000
          Purchase of reserves, net of future
             development costs                     576,234,000       50,000,000     133,103,000
          Development costs incurred during
             the period which reduced future
             development costs                      44,332,000       43,810,000      16,519,000
          Revisions of quantity estimates           40,905,000        7,397,000      26,167,000
          Sales of reserves in place                (6,499,000)      (7,933,000)     (5,281,000)
          Accretion of discount                     53,425,000       39,821,000      38,047,000
          Net change in income taxes              (357,427,000)     (48,347,000)     (3,080,000)
          Other, primarily changes in timing       (62,299,000)      (1,556,000)    (30,293,000)

          Ending balance                       $ 1,176,217,000      445,900,000     358,206,000
</TABLE>
  15.     Supplemental Quarterly Financial Information  (Unaudited)

     Following  is a summary of  the unaudited interim results of
  operations for the years ended December 31, 1996 and 1995:
<TABLE>
<CAPTION>
                                                                1996
                                       First          Second        Third        Fourth
                                      Quarter        Quarter       Quarter      Quarter        Total

  Oil, gas and natural gas liquids
     <S>                            <C>            <C>           <C>           <C>          <C>
     sales                          $33,734,229    36,743,221    39,007,410    53,073,462   162,558,322
  Total revenues                    $34,048,060    37,298,613    39,473,680    53,196,531   164,016,884
  Net earnings                      $ 5,553,926     6,775,388     7,707,673    14,763,545    34,800,532
  Net earnings per share:
     Assuming no dilution                 $0.25          0.31          0.35          0.66          1.57
     Assuming full dilution               $0.25          0.31          0.35          0.59          1.52

<CAPTION>
<F1>
                                                 1995 - Actual Reported Results (a)
                                       First        Second        Third           Fourth
                                      Quarter       Quarter      Quarter         Quarter        Total

  Oil, gas and natural gas 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

<CAPTION>
                                                                
<F1>
                                                      1995 - Adjusted Results (a)                 
                                       First        Second           Third       Fourth
                                      Quarter       Quarter          Quarter     Quarter        Total

  Oil, gas and natural gas 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    4,385,144     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  second table  above
  includes the 1995 quarterly results as  reported, including the
  six-month  out-of-period effect  on  the  third quarter.    The
  third table above presents the  1995 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>
<PAGE>

ITEM 9.   CHANGES  IN  AND  DISAGREEMENTS  WITH  ACCOUNTANTS   ON
          ACCOUNTING AND FINANCIAL DISCLOSURE

          Not applicable.


                            PART III


ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

            The  information  called  for  by  this  Item  10  is
incorporated   herein  by  reference  to  the  definitive   Proxy
Statement  to be filed by the Company pursuant to Regulation  14A
of  the  General  Rules and Regulations under the Securities  and
Exchange Act of 1934 not later than April 30, 1997.


ITEM 11.  EXECUTIVE COMPENSATION

            The  information  called  for  by  this  Item  11  is
incorporated   herein  by  reference  to  the  definitive   Proxy
Statement  to be filed by the Company pursuant to Regulation  14A
of  the  General  Rules and Regulations under the Securities  and
Exchange Act of 1934 not later than April 30, 1997.


ITEM 12.  SECURITY  OWNERSHIP  OF CERTAIN BENEFICIAL  OWNERS  AND
          MANAGEMENT

            The  information  called  for  by  this  Item  12  is
incorporated   herein  by  reference  to  the  definitive   Proxy
Statement  to be filed by the Company pursuant to Regulation  14A
of  the  General  Rules and Regulations under the Securities  and
Exchange Act of 1934 not later than April 30, 1997.



ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

            The  information  called  for  by  this  Item  13  is
incorporated   herein  by  reference  to  the  definitive   Proxy
Statement  to be filed by the Company pursuant to Regulation  14A
of  the  General  Rules and Regulations under the Securities  and
Exchange Act of 1934 not later than April 30, 1997.

<PAGE>
                            PART IV


ITEM 14.  EXHIBITS, FINANCIAL STATEMENTS AND SCHEDULES, AND
          REPORTS ON FORM 8-K

          (a)  The following documents are filed as part of this
          report:

          1.   Consolidated Financial Statements

                      Reference   is  made  to   the   Index   to
               Consolidated Financial Statements and Consolidated
               Financial Statement Schedules appearing at Item  8
               on Page 42 of this report.

          2.   Consolidated Financial Statement Schedules

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

          3.   Exhibits

                              2.1   Agreement and Plan of  Merger
                   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
                   among  Registrant,  Devon  Energy  Corporation
                   (Nevada),  Kerr-McGee Corporation,  Kerr-McGee
                   North  American Onshore Corporation and  Kerr-
                   McGee  Canada Onshore Ltd., dated October  17,
                   1996 (incorporated by reference to Addendum  A
                   to  Registrant's  definitive  proxy  statement
                   for  a  special meeting of shareholders, filed
                   on November 6, 1996).

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

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

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

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

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

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

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

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

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

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

                              4.8  Indenture dated as of July  3,
                   1996,  between the Registrant and The Bank  of
                   New   York   [incorporated  by  reference   to
                   Exhibit   4.7   to   Amendment   No.   1    to
                   Registrant's Registration Statement on Form S-
                   3 (No. 333-00815)].

                              4.9   First Supplemental  Indenture
                   dated   as  of  July  3,  1996,  between   the
                   Registrant   and   The  Bank   of   New   York
                   [incorporated by reference to Exhibit  4.8  to
                   Amendment  No. 1 to Registrant's  Registration
                   Statement on Form S-3 (No. 333-00815)].

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

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

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

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

                              4.14 Registration Rights Agreement,
                   dated   December  31,  1996,  by  and  between
                   Registrant    and    Kerr-McGee    Corporation
                   (incorporated by reference to Exhibit  4.4  to
                   Registrant's Current Report on Form 8-K  dated
                   December 31, 1996).

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

                              10.2 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)].*

                              10.3 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).*

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

                              10.5  Severance  Agreement  between
                   Devon   Energy  Corporation  (Nevada),   Devon
                   Energy  Corporation (Delaware) 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).*

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

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

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

                              10.9  Severance  Agreement  between
                   Devon   Energy  Corporation  (Nevada),   Devon
                   Energy  Corporation (Delaware) and Mr. William
                   T.    Vaughn,   dated   December    3,    1992
                   (incorporated  by reference to  Exhibit  10.15
                   to  Registrant's  Amendment No.  1  to  Annual
                   Report  on  Form  10-K  for  the  year   ended
                   December 31, 1992).*

                                10.10       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).

                              10.11     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).

                                10.12       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).

                                10.13       Registration   Rights
                   Agreement  dated July 3, 1996,  by  and  among
                   the  Registrant,  Devon  Financing  Trust  and
                   Morgan     Stanley    &    Co.    Incorporated
                   [incorporated by reference to Exhibit 10.1  to
                   Amendment  No. 1 to Registrant's  Registration
                   Statement on Form S-3 (No. 333-00815)].

                   11   Computation of earnings per share

                   12   Computation  of ratio of earnings  to  fixed charges

                   21   Subsidiaries of Registrant

                 23.1   Consent  of  LaRoche  Petroleum Consultants, Ltd.

                 23.2   Consent of AMH Group Ltd.

                 23.3   Consent  of KPMG  Peat  Marwick LLP

             * Compensatory plans or arrangements.

          (b)       Reports on Form 8-K - No reports on Form  8-K
          were  filed  during  the fourth  quarter  of  1996.   A
          Current Report on Form 8-K dated January 14, 1997,  was
          filed  by  the  Registrant regarding the  December  31,
          1996, acquisition of the KMG-NAOS Properties.

<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 6, 1997            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 6, 1997            By   John W. Nichols
                              John W. Nichols
                              Chairman of the Board and Director


March 6, 1997            By   J. Larry Nichols
                              J. Larry Nichols
                              President, Chief Executive Officer and Director


March 6, 1997            By   H. R. Sanders, Jr.
                              H. R. Sanders, Jr.
                              Executive Vice President and Director


March 6, 1997            By   William T. Vaughn
                              William T. Vaughn
                              Vice President - Finance


March 6, 1997            By   Danny J. Heatly
                              Danny J. Heatly
                              Controller

<PAGE>



March 6, 1997            By   Luke R. Corbett
                              Luke R. Corbett, Director


March 6, 1997            By   Thomas F. Ferguson
                              Thomas F. Ferguson, Director



March 6, 1997            By   David M. Gavrin
                              David M. Gavrin, Director



March 6, 1997            By   Michael E. Gellert
                              Michael E. Gellert, Director



March 6, 1997            By   Tom J. McDaniel
                              Tom J. McDaniel, Director



March 6, 1997            By   Lawrence H. Towell
                              Lawrence H. Towell, Director
<PAGE>

                        INDEX TO EXHIBITS

                                                        Page
2.1   Agreement    and   Plan   of   Merger    and
      Reorganization  by and among Registrant  and
      Devon   Energy   Corporation,   a   Delaware
      corporation, dated as of April 13, 1995            #
2.2   Agreement   and   Plan   of   Merger   among
      Registrant,    Devon   Energy    Corporation
      (Nevada),   Kerr-McGee  Corporation,   Kerr-
      McGee  North  American  Onshore  Corporation
      and  Kerr-McGee Canada Onshore  Ltd.,  dated
      October 17, 1996                                   #
3.1   Registrant's  Certificate of  Incorporation,
      as amended                                         #
3.2   Registrant's  Certificate  of  Amendment  of
      Certificate of Incorporation                       #
3.3   Registrant's Bylaws                                #
4.1   Form of Common Stock Certificate                   #
4.2   Rights Agreement between Registrant and  The
      First National Bank of Boston                      #
4.3   First  Amendment to Rights Agreement between
      Registrant  and The First National  Bank  of
      Boston dated October 16, 1996                      #
4.4   Second   Amendment   to   Rights   Agreement
      between  Registrant and the  First  National
      Bank of Boston, dated December 31, 1996            #
4.5   Certificate  of  Designations  of  Series  A
      Junior  Participating  Preferred  Stock   of
      Registrant                                         #
4.6   Certificate  of  Trust  of  Devon  Financing
      Trust                                              #
4.7   Amended  and Restated Declaration  of  Trust
      of  Devon Financing Trust dated as  of  July
      3,  1996,  by  J.  Larry Nichols,  H.  Allen
      Turner, William T. Vaughn, The Bank  of  New
      York (Delaware) and The Bank of New York  as
      Trustees and the Registrant as Sponsor             #
4.8   Indenture dated as of July 3, 1996,  between
      the Registrant and The Bank of New York            #
4.9   First  Supplemental Indenture  dated  as  of
      July  3,  1996,  between the Registrant  and
      The Bank of New York                               #
4.10  Form   of   6   1/2%  Preferred  Convertible
      Securities  (included  as  Exhibit  A-1   to
      Exhibit 4.5 above)                                 #
4.11  Form    of   6   1/2%   Convertible   Junior
      Subordinated    Debentures   (included    in
      Exhibit 4.7 above)                                 #
4.12  Preferred   Securities  Guarantee  Agreement
      dated  July 3, 1996, between Registrant,  as
      Guarantor,  and  The Bank of  New  York,  as
      Preferred Guarantee Trustee                        #
4.13  Stock   Rights  and  Restrictions  Agreement
      dated  as  of  December  31,  1996,  between
      Registrant and Kerr-McGee Corporation              #
4.14  Registration    Rights   Agreement,    dated
      December   31,   1996,   by   and    between
      Registrant and Kerr-McGee Corporation              #
10.1  Credit  Agreement  dated  August  30,  1996,
      among Devon Energy Corporation (Nevada),  as
      Borrower,  the Registrant and  Devon  Energy
      Operating    Corporation,   as   Guarantors,
      NationsBank  of Texas, N.A., as  Agent,  and
      NationsBank  of  Texas,  N.A.,   Bank   One,
      Texas,  N.A.,  Bank of Montreal,  and  First
      Union  National Bank of North  Carolina,  as
      Lenders                                            #
10.2  Devon  Energy Corporation 1988 Stock  Option
      Plan                                               #
10.3  Devon  Energy Corporation 1993 Stock  Option
      Plan                                               #
10.4  Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware)  and  Mr.  J.  Larry
      Nichols, dated December 3, 1992                    #
10.5  Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware)  and   Mr.   H.   R.
      Sanders, Jr., dated December 3, 1992               #
10.6  Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware) and Mr.  J.  Michael
      Lacey, dated December 3, 1992                      #
10.7  Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware)  and  Mr.  H.  Allen
      Turner, dated December 3, 1992                     #
10.8  Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware) and  Mr.  Darryl  G.
      Smette, dated December 3, 1992                     #
10.9  Severance  Agreement  between  Devon  Energy
      Corporation    (Nevada),    Devon     Energy
      Corporation  (Delaware) and Mr.  William  T.
      Vaughn, dated December 3, 1992                     #
10.10 Sale  and  Purchase  Agreement  relating  to
      Registrant's San Juan Basin gas properties         #
10.11 Second Restatement of and Amendment to  Sale
      and    Purchase   Agreement   relating    to
      Registrant's San Juan Basin gas properties         #
10.12 Purchase  and  Sale Agreement between  Union
      Oil  Company of California and Devon  Energy
      Corporation (Nevada)                               #
10.13 Registration Rights Agreement dated July  3,
      1996,  by  and  among the Registrant,  Devon
      Financing  Trust and Morgan  Stanley  &  Co.
      Incorporated                                       #
11    Computation of earnings per share                 93
12    Computation  of ratio of earnings  to  fixed
      charges                                           94
21    Subsidiaries of Registrant                        95
23.1  Consent  of  LaRoche Petroleum  Consultants,
      Ltd.                                              96
23.2  Consent of AMH Group Ltd.                         97
23.3  Consent of KPMG Peat Marwick LLP                  98
____________________________________
#  Incorporated by reference.
<PAGE>