DEVON ENERGY CORP/DE - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)
X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
- ----- OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2002

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
- ------ OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File No. 000-30176

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

DELAWARE 73-1567067
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Number)

20 NORTH BROADWAY
OKLAHOMA CITY, OKLAHOMA 73102-8260
(Address of Principal Executive Offices) (Zip Code)

Registrant's telephone number, including area code: (405) 235-3611

Not applicable
- -------------------------------------------------------------------------------
(Former name, former address and former fiscal year,
if changed from last report)

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 the past 90 days. Yes X No .

The number of shares outstanding of Registrant's common stock, par
value $.10, as of October 31, 2002, was 156,666,000.

1 of 56 total pages
(Exhibit Index is found at page 50)

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DEVON ENERGY CORPORATION

Index to Form 10-Q Quarterly Report
to the Securities and Exchange Commission

DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"Bcf" means billion cubic feet
"Bbl" means barrel
"MBbls" means thousand barrels
"MMBbls" means million barrels
"Boe" means equivalent barrels of oil
"MMBoe" means million equivalent barrels of oil
"Oil" includes crude oil and condensate
"NGLs" means natural gas liquids
"C$" means Canadian dollar

2

DEVON ENERGY CORPORATION

PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2002 AND 2001

(FORMING A PART OF FORM 10-Q QUARTERLY REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION)

3

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

See accompanying notes to consolidated financial statements.

4

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

See accompanying notes to consolidated financial statements.

5

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

See accompanying notes to consolidated financial statements.

6

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS
(IN MILLIONS)

See accompanying notes to consolidated financial statements.

7

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

See accompanying notes to consolidated financial statements.

8

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accompanying consolidated financial statements and notes thereto of
Devon Energy Corporation ("Devon") have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. Accordingly, certain
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States of America
have been omitted. The accompanying consolidated financial statements and notes
thereto should be read in conjunction with the consolidated financial statements
and notes thereto included in Devon's Current Report on Form 8-K filed October
3, 2002.

In the opinion of Devon's management, all adjustments (all of which are
normal and recurring) have been made which are necessary to fairly state the
consolidated financial position of Devon and its subsidiaries as of September
30, 2002, and the results of their operations and their cash flows for the
three-month and nine-month periods ended September 30, 2002 and 2001. Certain of
the 2001 amounts in the accompanying consolidated financial statements have been
reclassified to conform to the 2002 presentation.

2. BUSINESS COMBINATIONS AND PRO FORMA INFORMATION

Mitchell Energy & Development Corp. Merger

On January 24, 2002, Devon completed its acquisition of Mitchell Energy
& Development Corp. ("Mitchell"). Under the terms of this merger, Devon issued
approximately 30 million shares of Devon common stock and paid $1.6 billion in
cash to the Mitchell stockholders. The cash portion of the acquisition was
funded from borrowings under a $3.0 billion senior unsecured term loan credit
facility (see Note 3).

Devon acquired Mitchell for the significant development and
exploitation projects in each of Mitchell's core areas, increased marketing and
midstream operations and increased exposure to the North American natural gas
market.

The calculation of the purchase price and the preliminary allocation to
assets and liabilities as of January 24, 2002, are shown below. The purchase
price allocation is preliminary because certain items such as the determination
of the final tax bases and fair value of the assets and liabilities as of the
acquisition date are subject to change.

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Anderson Exploration Ltd. Acquisition

On October 17, 2001, Devon completed its acquisition of all the common
shares of Anderson Exploration Ltd. ("Anderson"). The cost to Devon of acquiring
Anderson's outstanding common shares and paying for the intrinsic value of
Anderson's outstanding options and appreciation rights was approximately $3.5
billion, which was funded from the sale of $3.0 billion of debt securities and
borrowings under a $3.0 billion senior unsecured term loan credit facility (see
Note 3).

Pro Forma Information

Set forth in the following table is certain unaudited pro forma
financial information for the nine-month periods ended September 30, 2002 and
2001. The information for the nine-month periods ended September 30, 2002 and
2001, has been prepared assuming the Anderson acquisition and the Mitchell
merger were consummated on January 1, 2001. All pro forma information is based
on estimates and assumptions deemed appropriate by Devon. The pro forma
information is presented for illustrative purposes only. If the transactions had
occurred in the past, Devon's operating results might have been different from
those presented in the following table. The pro forma information should not be
relied upon as an indication of the operating results that Devon would have
achieved if the transactions had occurred on January 1, 2001. The pro forma
information also should not be used as an indication of the future results that
Devon will achieve after the transactions.

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The following should be considered in connection with the pro forma
financial information presented:

- On February 12, 2001, Anderson acquired all of the outstanding shares
of Numac Energy Inc. The summary unaudited pro forma combined statements of
operations do not include any results from Numac's operations prior to February
12, 2001.

- Devon's historical results of operations for the nine-month period
ended September 30, 2001 include $25 million of amortization expense for
goodwill related to previous mergers. As of January 1, 2002, in accordance with
new accounting pronouncements, such goodwill is no longer amortized, but instead
is tested for impairment at least annually. No goodwill amortization expense has
been recognized in the pro forma statements of operations for the goodwill
related to the Anderson acquisition or the Mitchell merger.

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3. LONG-TERM DEBT

$3 Billion Term Loan Credit Facility

Prior to December 31, 2001, Devon used proceeds of $1 billion of a $3
billion term loan credit facility to partially fund the Anderson acquisition.
The remaining $2 billion of availability was utilized upon the closing of the
Mitchell acquisition on January 24, 2002. As of September 30, 2002, $1.9 billion
of the balance outstanding was retired. The primary sources of the repayments
were the issuance of $1 billion of debt securities, of which $0.8 billion was
used to pay down debt, and $1.1 billion from the sale of certain oil and gas
properties. As of September 30, 2002, the balance outstanding under the term
loan credit facility was $1.1 billion at an average rate of 2.8%.

Debt Securities

On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15,
2032. The net proceeds received, after discounts and issuance costs, were $986
million. The debt securities are unsecured and unsubordinated obligations of
Devon. The net proceeds were partially used to pay down $820 million on Devon's
$3 billion term loan credit facility. The remaining $166 million of net proceeds
was used in June 2002 to partially fund the early extinguishment of $175 million
of 8.75% senior notes due June 15, 2007. The notes were redeemed at 104.375% of
principal, or approximately $183 million.

Commercial Paper

As of September 30, 2002, Devon had $78 million of borrowings under its
commercial paper program at an average rate of 2.3%. Because Devon has the
intent and ability to refinance the balance due with borrowings under its credit
facilities, the $78 million outstanding under the commercial paper program was
classified as long-term debt on the September 30, 2002 consolidated balance
sheet.

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Credit Facilities

Devon has $1 billion of unsecured long-term credit facilities (the
"Credit Facilities"). The Credit Facilities include a U.S. facility of $725
million (the "U.S. Facility") and a Canadian facility of $275 million (the
"Canadian Facility"). The $725 million U.S. Facility consists of a Tranche A
facility of $200 million and a Tranche B facility of $525 million. On June 7,
2002, Devon renewed the $525 million Tranche B facility and its $275 million
Canadian facility.

The Tranche A facility matures on October 15, 2004. Devon may borrow
funds under the Tranche B facility until June 5, 2003 (the "Tranche B Revolving
Period"). Devon may request that the Tranche B Revolving Period be extended an
additional 364 days by notifying the agent bank of such request between 30 and
60 days prior to the end of the Tranche B Revolving Period. On June 6, 2003, at
the end of the Tranche B Revolving Period, Devon may convert the then
outstanding balance under the Tranche B facility to a two-year term loan by
paying the Agent a fee of 12.5 basis points. The applicable borrowing rate would
be at LIBOR plus 125 basis points. On September 30, 2002, there were no
borrowings outstanding under the $725 million U.S. Facility. The available
capacity under the U.S. Facility as of September 30, 2002, net of commercial
paper borrowings and outstanding letters of credit, was $623 million.

Devon may borrow funds under the $275 million Canadian Facility until
June 5, 2003 (the "Canadian Facility Revolving Period"). Devon may request that
the Canadian Facility Revolving Period be extended an additional 364 days by
notifying the agent bank of such request between 30 and 60 days prior to the end
of the Canadian Facility Revolving Period. Debt outstanding as of the end of the
Canadian Facility Revolving Period is payable in semiannual installments of 2.5%
each for the following five years, with the final installment due five years and
one day following the end of the Canadian Facility Revolving Period. On
September 30, 2002, there were no borrowings under the $275 million Canadian
facility.

Under the terms of the Credit Facilities, Devon has the right to
reallocate up to $100 million of the unused Tranche B facility maximum credit
amount to the Canadian Facility. Conversely, Devon also has the right to
reallocate up to $100 million of unused Canadian Facility maximum credit amount
to the Tranche B Facility.

Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate. Devon may also elect to borrow at the
prime rate. The Credit Facilities provide for an annual facility fee of $1.4
million that is payable quarterly.

Devon's $1 billion revolving credit facilities and its $3 billion term
loan credit facility each contain only one material financial covenant. This
covenant requires Devon to maintain a ratio of total funded debt to total
capitalization of no more than 65%. The credit agreements contain definitions of
total funded debt and total capitalization that include adjustments to the
respective amounts reported in Devon's consolidated financial statements. Per
the agreements, total funded debt excludes the debentures that are exchangeable
into shares of ChevronTexaco Corporation common stock. Also, total
capitalization is adjusted to add back noncash financial writedowns such as full
cost ceiling property impairments or goodwill impairments. As of September 30,
2002,

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Devon's ratio of total funded debt to total capitalization, as defined in its
credit agreements, was 55.8%.

Letter of Credit Facility

On July 25, 2002, Devon renewed and increased its letter of credit and
revolving bank facility ("LOC Facility") for its Canadian operations. This C$150
million LOC Facility will be used primarily by Devon's wholly-owned
subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to
issue letters of credit. As of September 30, 2002, C$105 million ($ 66 million
converted to U.S. dollars using the September 30, 2002 exchange rate) of letters
of credit were issued under the LOC Facility primarily for Canadian drilling
commitments.

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Devon has periodically entered into oil and gas financial instruments
and foreign exchange rate swaps to manage its exposure to oil and gas price
volatility. The foreign exchange rate swaps mitigate the effect of volatility in
the Canadian-to-U.S. dollar exchange rate on certain Canadian gas revenues that
are based on U.S. dollar prices. The hedging instruments are usually placed with
counterparties that Devon believes are minimal credit risks. It is Devon's
policy to only enter into derivative contracts with investment grade rated
counterparties deemed by management to be competent and competitive market
makers. The oil and gas reference prices upon which the price hedging
instruments are based reflect various market indices that have a high degree of
historical correlation with actual prices received by Devon.

As of September 30, 2002, $82 million of net deferred losses on
derivative instruments in "accumulated other comprehensive loss" are expected to
be reclassified to earnings from operations during the next 12 months.
Transactions and events expected to occur over the next 12 months that will
necessitate reclassifying these derivatives' losses to earnings from operations
are primarily the production and sale of the hedged oil and gas quantities. The
maximum term over which Devon is hedging exposures to the variability of cash
flows for commodity price risk is 27 months.

Devon recorded in its statements of operations a gain of $21 million
and $2 million in the third quarter of 2002 and 2001, respectively, and a gain
of $28 million and a loss of $5 million in the nine-month periods ended
September 30, 2002 and 2001, respectively, for the change in fair value of
derivative instruments that do not qualify for hedge accounting treatment, as
well as the ineffectiveness of derivatives that do qualify as hedges. Included
in the three-month periods ended September 30, 2002 and 2001 are a net loss of
$3 million and $1 million, respectively, related to such ineffectiveness.
Included in the nine-month periods ended September 30, 2002 and 2001 are a net
gain of $7 million and a net loss of $1 million, respectively, related to such
ineffectiveness. These gains and losses are related to both (i) the
ineffectiveness of the various cash flow hedges and (ii) the component of the
derivative instrument gain or loss excluded from the assessment of hedge
effectiveness.

5. GOODWILL

Effective January 1, 2002, Devon adopted the remaining provisions of
Statement of Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets (SFAS No. 142).

15

Under SFAS No. 142, goodwill and intangible assets with indefinite useful lives
are no longer amortized, but are instead tested for impairment at least
annually.

As of January 1, 2002, Devon had unamortized goodwill in the amount of
$2.2 billion, which was subject to the transition goodwill impairment assessment
provisions of SFAS No. 142. Devon has completed its assessment of the fair value
of its reporting units and compared such fair value to each reporting unit's
carrying value, including goodwill, as of January 1, 2002. Based on this
assessment, no transitional impairment of the carrying value of goodwill was
required.

As a result of the January 2002 Mitchell acquisition, goodwill
increased $1.4 billion. All of the Mitchell-related goodwill is recorded in
Devon's U.S. segment.

Following is a reconciliation of reported net income and the related
earnings per share amounts assuming the provisions of SFAS No. 142 had been
adopted as of January 1, 2001.

6. EARNINGS PER SHARE

The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
the three-month periods ended September 30, 2002 and 2001 and the nine-month
period ended September 30, 2001. The diluted earnings per share calculations for
the nine-month period ended September 30, 2002 produce results that are
anti-dilutive as a result of the loss on continuing operations. (The diluted
calculation for the nine months ended September 30, 2002 increased the net
earnings by $5 million and increased the common shares outstanding by 6 million
shares.) Therefore, the diluted earnings per share amounts for the nine-month
period ended September 30, 2002 reported in the accompanying consolidated
statements of operations are the same as the basic earnings per share amounts.

The senior convertible debentures were not included in the dilution
calculation for the three-month period ended September 30, 2002, because the
inclusion was anti-dilutive.

Options to purchase approximately 3.3 million shares of Devon's common
stock with exercise prices ranging from $44.60 per share to $89.66 per share
(with a weighted average price of $53.89 per share) were outstanding at
September 30, 2002, but were not included in the computation of diluted earnings
per share for the third quarter of 2002 because the options' exercise prices
exceeded the average market price of Devon's common stock during the period.
Similarly, options to purchase approximately 3.0 million shares of Devon's
common stock with exercise prices ranging from $45.49 per share to $89.66 per
share (with a weighted average price of $55.58 per share) were excluded from the
diluted earnings per share calculation for the third quarter of 2001. The
excluded options for the 2002 period expire between November 30, 2002 and May
16, 2012.

All options to purchase Devon common stock were excluded from the
diluted earnings per share calculations for the first nine months of 2002
because of the anti-dilutive effect of such

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options. Options to purchase approximately 1.1 million shares of Devon's common
stock with exercise prices ranging from $52.39 per share to $89.66 per share
(with a weighted average price of $63.44 per share) were excluded from the
diluted earnings per share calculation for the first nine months of 2001.

7. REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES

Under the full cost method of accounting, the net book value of oil and
gas properties less related deferred income taxes (the "costs to be recovered")
may not exceed a calculated "full cost ceiling." The ceiling limitation is the
discounted estimated after-tax future net revenues from oil and gas properties
plus the cost of properties not subject to amortization. The ceiling is imposed
separately by country. In calculating future net revenues, current prices and
costs are generally held constant indefinitely, and Devon does not include the
effect of hedges in the calculation of the future net revenues. Therefore, the
ceiling limitation is not necessarily indicative of the properties' fair value.
The costs to be recovered are compared to the ceiling on a quarterly basis. If
the costs to be recovered exceed the ceiling, the excess is written off as an
expense.

An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling
applicable to the subsequent period.

Based on oil and natural gas cash market prices as of June 30, 2002,
Devon's Canadian costs to be recovered exceeded the related ceiling value by
$371 million. This after-tax amount resulted in a pre-tax reduction of the
carrying value of Devon's Canadian oil and gas properties of $651 million in the
second quarter of 2002. This reduction was the result of a sharp drop in
Canadian gas prices during the last half of June 2002. The June 30, 2002,
reference prices used in the Canadian ceiling calculation, expressed in Canadian
dollars based on an exchange ratio of $0.6585, were a NYMEX price of C$40.79 per
barrel of oil and an AECO price of C$2.17 per Mcf of gas. The cash market prices
of natural gas increased during the month of July 2002 prior to Devon's release
of its second quarter results, but the increase was not sufficient to offset the
entire reduction calculated as of June 30.

8. DISCONTINUED OPERATIONS

Effective January 1, 2002, Devon was required to adopt SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets, which supersedes
both SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions
of APB Opinion No. 30, Reporting the Results of Operations-Reporting the Effects
of Disposal of a Segment of a Business, and Extraordinary, Unusual and
Infrequently Occurring Events and Transactions, for the disposal of a segment of
a business (as previously defined in that Opinion).

On April 18, 2002, Devon, sold its Indonesian operations to PetroChina
Company Limited for total cash consideration of $250 million. In accordance with
SFAS No. 144, Devon has reclassified the assets, liabilities and results of its
Indonesian operations, which were included in Devon's International segment, as
discontinued operations for each of the periods presented.

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On August 13, 2002, Devon announced that it had entered into an
agreement to sell its operations in Argentina to Petroleo Brasileiro S.A. -
Petrobras. The purchase price was approximately $90 million. Devon completed
this sale in October 2002. In accordance with SFAS No. 144, Devon has recognized
a loss in the third quarter of 2002 of $55 million from the divestiture, and has
reclassified the assets, liabilities and results of its Argentine operations,
which were included in Devon's International segment, as discontinued operations
for each of the periods presented.

The following tables include the major classes of assets and
liabilities and the revenues that were reclassified.

9. SUPPLEMENTAL CASH FLOW INFORMATION

Cash payments (refunds) for interest and income taxes in the first nine
months of 2002 and 2001 are presented below:

20

The 2002 Mitchell acquisition involved non-cash consideration as
presented below:

10. SEGMENT INFORMATION

Devon manages its business by country. As such, Devon identifies its
segments based on geographic areas. Devon has three segments: its operations in
the U.S., its operations in Canada and its international operations outside of
North America. Substantially all of these segments' operations involve oil and
gas producing and marketing and midstream activities. Following is certain
financial information regarding Devon's segments. The revenues reported are all
from external customers.

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10. SEGMENT INFORMATION (CONTINUED)

22

10. SEGMENT INFORMATION (CONTINUED)

23

10. SEGMENT INFORMATION (CONTINUED)

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10. SEGMENT INFORMATION (CONTINUED)

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11. COMMITMENTS AND CONTINGENCIES

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

Environmental Matters

Devon is subject to certain laws and regulations relating to
environmental remediation activities associated with past operations, such as
the Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA") and similar state statutes. In response to liabilities associated
with these activities, accruals have been established when reasonable estimates
are possible. Such accruals primarily include estimated costs associated with
remediation. Devon has not used discounting in determining its accrued
liabilities for environmental remediation, and no material claims for possible
recovery from third party insurers or other parties related to environmental
costs have been recognized in Devon's consolidated financial statements. Devon
adjusts the accruals when new remediation responsibilities are discovered and
probable costs become estimable, or when current remediation estimates must be
adjusted to reflect new information.

Certain of Devon's subsidiaries acquired in the 1999 merger with
PennzEnergy Company are involved in matters in which it has been alleged that
such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or
similar state legislation with respect to various waste disposal areas owned or
operated by third parties. As of September 30, 2002, Devon's consolidated
balance sheet included $9 million of non-current accrued liabilities, reflected
in "Other liabilities," related to these and other environmental remediation
liabilities. Devon does not currently believe there is a reasonable possibility
of incurring additional material costs in excess of the current accruals
recognized for such environmental remediation activities. With respect to the
sites in which Devon subsidiaries are PRPs, Devon's conclusion is based in large
part on (i) the availability of defenses to liability, including the
availability of the "petroleum exclusion" under CERCLA and similar state laws,
and/or (ii) Devon's current belief that its share of wastes at a particular site
is or will be viewed by the Environmental Protection Agency or other PRPs as
being de minimis. As a result, Devon's monetary exposure is not expected to be
material.

Royalty Matters

Numerous gas producers and related parties, including Devon, have been
named in various lawsuits filed by private litigants alleging violation of the
federal False Claims Act. The suits allege that the producers and related
parties used below-market prices, improper deductions, improper measurement
techniques and transactions with affiliates which resulted in underpayment of
royalties in connection with natural gas and natural gas liquids produced and
sold from federal and Indian owned or controlled lands. The various suits have
been consolidated by the United States Judicial Panel on Multidistrict
Litigation for pre-trial proceedings in the matter of In re Natural Gas
Royalties Qui Tam Litigation, MDL-1293, United States District

26

Court for the District of Wyoming. Devon believes that it has acted reasonably,
has legitimate and strong defenses to all allegations in the suits, and has paid
royalties in good faith. Devon does not currently believe that it is subject to
material exposure in association with these lawsuits and no liability has been
recorded in connection therewith.

Devon is involved in other various routine legal proceedings incidental
to its business. However, to Devon's knowledge as of the date of this report,
there were no other material pending legal proceedings to which Devon is a party
or to which any of its property is subject.

12. IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 requires liability recognition for
retirement obligations associated with tangible long-lived assets, such as
producing well sites, offshore production platforms, and natural gas processing
plants. The obligations included within the scope of SFAS No. 143 are those for
which a company faces a legal obligation for settlement. The initial measurement
of the asset retirement obligation is to be fair value, defined as "the price
that an entity would have to pay a willing third party of comparable credit
standing to assume the liability in a current transaction other than in a forced
or liquidation sale." Devon expects that it will use a valuation technique such
as present value of expected cash outflows to estimate fair value.

The asset retirement cost equal to the fair value of the retirement
obligation is to be capitalized as part of the cost of the related long-lived
asset and allocated to expense using a systematic and rational method.

Devon will be required to adopt SFAS No. 143 effective January 1, 2003
using a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depreciation.

Devon currently includes estimated costs of dismantlement, removal,
site reclamation, and other similar activities in the total costs that are
subject to depreciation, depletion, and amortization. Devon does not record a
separate asset or liability for such amounts. Devon has not completed the
assessment of the impact that adoption of SFAS No. 143 will have on its
consolidated financial statements.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

The following discussion addresses material changes in results of
operations for the three- month and nine-month periods ended September 30, 2002,
compared to the three-month and nine-month periods ended September 30, 2001, and
in financial condition since December 31, 2001. It is presumed that readers have
read or have access to Devon's 2001 Annual Report on Form 10-K which includes
disclosures regarding critical accounting policies as part of Management's
Discussion and Analysis of Financial Condition and Results of Operations.

OVERVIEW

Devon recorded net earnings for the third quarter of 2002 of $62
million, or $0.38 per share. This compares to net earnings of $85 million, or
$0.65 per share for the third quarter of 2001. Net earnings for the first nine
months of 2002 were $20 million, or $0.08 per share. This compares to net
earnings for the first nine months of 2001 of $621 million, or $4.79 per share.
The decrease in third quarter net earnings was due to the effect of the
discontinued operations. The decrease in the first nine months' net earnings was
due to a decline in oil, natural gas and NGL prices and increases in expenses,
including a $651 million reduction of carrying value of Canadian oil and gas
properties. These negative effects in both periods were partially offset by an
increase in production from the Anderson and Mitchell acquisitions.
Additionally, the nine month period ended September 30, 2002, benefited from a
net gain from discontinued operations.

On January 24, 2002, Devon completed its acquisition of Mitchell. Under
the terms of this merger, Devon issued approximately 30 million shares of Devon
common stock and paid $1.6 billion in cash to the Mitchell stockholders. The
cash portion of the acquisition was funded from borrowings under a $3.0 billion
senior unsecured term loan credit facility.

On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15,
2032. The net proceeds received, after discounts and issuance costs, were $986
million. The debt securities are unsecured and unsubordinated obligations of
Devon. The net proceeds were partially used to pay down $820 million on Devon's
$3 billion term loan credit facility. The remaining $166 million of net proceeds
was used in June 2002 to partially fund the early extinguishment of $175 million
of 8.75% senior notes due June 15, 2007. The notes were redeemed at 104.375% of
principal, or approximately $183 million.

On June 7, 2002, Devon renewed the $800 million, 364-day portion of its
unsecured long-term credit facilities (the "Credit Facilities"). The Credit
Facilities include a U.S. facility of $725 million (the "U.S. Facility") and a
Canadian facility of $275 million (the "Canadian Facility").

On July 25, 2002, Devon renewed and increased its letter of credit and
revolving bank facility ("LOC Facility") for its Canadian operations. This C$150
million LOC Facility will be used primarily by Devon's wholly-owned
subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to
issue letters of credit.

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RESULTS OF OPERATIONS

Total revenues increased $495 million, or 92%, in the third quarter of
2002, and $887 million, or 40%, in the first nine months of 2002. This was the
result of increases in oil, gas and NGL production and an increase in marketing
and midstream revenue, partially offset by a decline in the combined average
price of oil, gas and NGLs. The increases in production and marketing and
midstream revenues were primarily the result of the Anderson and Mitchell
acquisitions.

Oil, gas and NGL revenues were up $243 million, or 46%, for the third
quarter of 2002 compared to the third quarter of 2001, and were up $242 million,
or 11%, for the first nine months of 2002 compared to the first nine months of
2001. The three-month and nine-month periods comparison of production and price
changes are shown in the following tables. (Note: Unless otherwise stated, all
dollar amounts are expressed in U.S. dollars.)

- ---------------

(1) Gas volumes are converted to Boe or MMBoe 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 NGL are affected by market and other factors in addition to
relative energy content.

30

In addition to the volumes included in the prior tables for domestic
and Canadian production, in the third quarter of 2002 and 2001, Devon also
produced 651,000 and 631,000 barrels of oil, respectively, in its International
division. The oil revenues generated by this production were $16 million and $15
million, respectively. In the first nine months of 2002 and 2001, Devon also
produced 1,518,000 and 2,078,000 barrels of oil, respectively, in its
International division. The oil revenues generated by this production were $40
million and $51 million, respectively.

The average sales prices per unit of production shown in the preceding
tables include the effect of Devon's hedging activities. Following is a
comparison of Devon's average sales prices with and without the effect of hedges
for the three-month and nine-month periods ended September 30, 2002 and 2001.

OIL REVENUES. Oil revenues increased $27 million, or 14%, in the third
quarter of 2002. Oil revenues increased $14 million due to a $1.36 per barrel
increase in the average price of oil. An increase in 2002's production of 1
million barrels also caused oil revenues to increase. The October 2001 Anderson
acquisition and the January 2002 Mitchell acquisition accounted for 3 million
barrels of increased production, partially offset by production lost from
divestitures of 2 million barrels.

Oil revenues increased $97 million, or 16%, in the first nine months of
2002. An increase in production of 7 million barrels, or 28%, caused oil
revenues to increase by $157 million. The Anderson and Mitchell acquisitions
accounted for 8 million barrels of increased production, partially offset by
production lost from divestitures of 2 million barrels. The effects of the
production increase were partially offset by a $1.86 per barrel decrease in the
average price of oil in 2002.

GAS REVENUES. Gas revenues increased $177 million, or 58%, in the third
quarter of 2002. An increase in production of 74 Bcf, or 66%, caused gas
revenues to increase by $202 million. The Anderson and Mitchell acquisitions
accounted for 94 Bcf of increased production, partially offset by production
lost from divestitures of 10 Bcf, as well as natural declines in production. The
effects of the production increase were partially offset by a $0.14 per Mcf
decrease in the average gas price in the third quarter of 2002.

31

Gas revenues increased $43 million, or 3%, in the first nine months of
2002. An increase in production of 249 Bcf, or 76%, caused gas revenues to
increase by $1.1 billion. The Anderson and Mitchell acquisitions accounted for
276 Bcf of increased production, partially offset by production lost from
divestitures of 10 Bcf, as well as natural declines in production. The effects
of the production increase were partially offset by a $1.86 per Mcf decrease in
the average gas price in the first nine months of 2002.

NGL REVENUES. NGL revenues increased $39 million in the third quarter
of 2002. A 3 million barrel increase in 2002 production caused revenues to
increase $47 million. The Anderson and Mitchell acquisitions accounted for 3
million barrels of increased production. The effects of the production increase
were partially offset by a $1.65 per barrel decrease in the average NGL price in
the third quarter of 2002.

NGL revenues increased $102 million in the first nine months of 2002. A
10 million barrel increase in 2002 production caused revenues to increase $191
million. The Anderson and Mitchell acquisitions accounted for 10 million barrels
of increased production. The effects of the production increase were partially
offset by a $6.09 per barrel decrease in the average NGL price in the first nine
months of 2002.

MARKETING AND MIDSTREAM REVENUES. Marketing and midstream revenues
increased $253 million and $645 million in the third quarter and first nine
months of 2002, respectively. The Mitchell acquisition included significant
marketing and midstream assets which accounted for the increase in revenues.

PRODUCTION AND OPERATING EXPENSES. The components of production and
operating expenses are set forth in the following tables.

Lease operating expenses increased $41 million and $148 million in the
third quarter and the first nine months of 2002, respectively. The Anderson and
Mitchell acquisitions accounted for $66 million and $189 million of the
increases, respectively. The historical Devon lease

32

operating expenses decreased $25 million and $41 million, respectively, due to
divestitures, lower fuel and electricity costs as well as lower third-party
field service costs.

Transportation costs increased $23 million and $63 million in the third
quarter and the first nine months of 2002, respectively, primarily due to an
increase in gas production from the Anderson and Mitchell acquisitions.

Production taxes increased $4 million in the third quarter of 2002 and
decreased $14 million in the first nine months of 2002. The majority of Devon's
production taxes are assessed on its onshore domestic properties. In the U.S.,
most of the production taxes are based on a fixed percentage of revenues.
Therefore, the 11% increase and 16% decrease in domestic oil, gas and NGL
revenues in the third quarter and first nine months of 2002, respectively, were
the primary causes of the production tax change.

MARKETING AND MIDSTREAM COSTS AND EXPENSES. Marketing and midstream
costs and expenses increased $209 million and $528 million in the third quarter
and the first nine months of 2002, respectively. The Mitchell acquisition
included significant marketing and midstream assets which accounted for the
increase in costs and expenses.

DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES ("DD&A"). Oil and gas
property related DD&A increased $70 million, or 38%, from $185 million in the
third quarter of 2001 to $255 million in the third quarter of 2002. Oil and gas
property related DD&A expense increased $102 million due to the 55% increase in
combined oil, gas and NGLs production in 2002. The effects of the production
increase were partially offset by a decrease in the combined U.S., Canadian and
international DD&A rate from $6.41 per Boe in 2001 to $5.68 per Boe in 2002. The
drop in the DD&A rate was primarily due to reductions of carrying value of oil
and gas properties in the U.S. and Canada in the fourth quarter of 2001, and in
Canada in the second quarter of 2002.

Oil and gas property related DD&A increased $326 million, or 63%, from
$515 million in the first nine months of 2001 to $841 million in the first nine
months of 2002. Oil and gas property related DD&A expense increased $353 million
due to the 68% increase in combined oil, gas and NGLs production in 2002. The
effects of the production increase were partially offset by a decrease in the
combined U.S., Canadian and international DD&A rate from $6.07 per Boe in 2001
to $5.88 per Boe in 2002. The rate decrease was primarily caused by the
reductions to property previously discussed.

Non-oil and gas property DD&A expense increased from $10 million in the
third quarter of 2001 to $28 million in the third quarter of 2002. Non-oil and
gas property DD&A expense increased from $29 million in the first nine months
ended of 2001 to $77 million in the first nine months ended of 2002.
Depreciation of the marketing and midstream assets acquired in the January 2002
Mitchell acquisition accounted for substantially all of the increase.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A"). Devon's net G&A consists
of three primary components. The largest of these components is the gross amount
of expenses incurred for personnel costs, office expenses, professional fees and
other G&A items. The gross amount of these expenses is partially reduced by two
offsetting components. One is the amount of G&A capitalized pursuant to the
full-cost method of accounting. The other is the amount of G&A

33

reimbursed by working interest owners of properties for which Devon serves as
the operator. These reimbursements are received during both the drilling and
operational stages of a property's life. The gross amount of G&A incurred, less
the amounts capitalized and reimbursed, is recorded as net G&A in the
consolidated statements of operations. The following table is a summary of G&A
expenses by component for the third quarter and first nine months of 2002 and
2001.

Net G&A increased $19 million and $73 million, or 68% and 94%, in the
third quarter and first nine months of 2002, respectively, compared to the same
periods of 2001. Gross G&A increased $32 million and $109 million, or 53% and
63%, in the third quarter and first nine months of 2002, respectively, compared
to the same periods of 2001. The increase in gross expenses in both periods of
2002 was primarily related to the Anderson and Mitchell acquisitions.

Capitalized G&A increased $8 million and $18 million in the third
quarter and first nine months of 2002, respectively. Reimbursed G&A increased $5
million and $18 million in the third quarter and first nine months of 2002,
respectively. Changes in both of the capitalized and reimbursed amounts were
primarily related to the Anderson and Mitchell acquisitions.

REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES. Under the full
cost method of accounting, the net book value of oil and gas properties less
related deferred income taxes (the "costs to be recovered"), may not exceed a
calculated "full cost ceiling." The ceiling limitation is the discounted
estimated after-tax future net revenues from oil and gas properties plus the
cost of properties not subject to amortization. The ceiling is imposed
separately by country. In calculating future net revenues, current prices and
costs are generally held constant indefinitely, and Devon does not include the
effect of hedges in the calculation of the future net revenues. Therefore, the
ceiling limitation is not necessarily indicative of the properties' fair value.
The costs to be recovered are compared to the ceiling on a quarterly basis. If
the costs to be recovered exceed the ceiling, the excess is written off as an
expense, except as discussed in the following paragraph.

If, subsequent to the end of the quarter but prior to the applicable
financial statements being published, prices increase to levels such that the
ceiling would exceed the costs to be recovered, a writedown otherwise indicated
at the end of the quarter is not required to be recorded. A writedown indicated
at the end of a quarter is also not required if the value of additional reserves
proved up on properties after the end of the quarter but prior to the publishing
of the financial statements would result in the ceiling exceeding the costs to
be recovered, as long as the properties were owned at the end of the quarter.

An expense recorded in one period may not be reversed in a subsequent
period even

34

though higher oil and gas prices may have increased the ceiling applicable to
the subsequent period.

Based on oil and natural gas cash market prices as of June 30, 2002,
Devon's Canadian costs to be recovered exceeded the related ceiling value by
$371 million. This after-tax amount resulted in a pre-tax reduction of the
carrying value of Devon's Canadian oil and gas properties of $651 million in the
second quarter of 2002. This reduction was the result of a sharp drop in
Canadian gas prices during the last half of June 2002. The June 30 reference
prices used in the Canadian ceiling calculation, expressed in Canadian dollars
based on an exchange ratio of $0.6585, were a NYMEX price of C$40.79 per barrel
of oil and an AECO price of C$2.17 per Mcf. The cash market prices of natural
gas increased during the month of July 2002 prior to Devon's release of its
second quarter results, but the increase was not sufficient to offset the entire
reduction calculated as of June 30.

Under the purchase method of accounting for business combinations,
acquired oil and gas properties are recorded at fair value as of the date of
purchase. Devon estimates such fair value using its estimates of future oil and
gas prices. In contrast, the ceiling calculation dictates that prices in effect
as of the last day of the applicable quarter are held constant indefinitely.
Accordingly, the resulting value is not necessarily indicative of the fair value
of the reserves. The oil and gas properties added from the Anderson acquisition
in 2001 were recorded at fair values that were based on expected future oil and
gas prices higher than the June 30, 2002, prices used to calculate the ceiling.

During the third quarter of 2001, Devon elected to discontinue
operations in Thailand. After meeting the drilling and capital commitments on
this property, Devon determined that the property did not meet Devon's internal
criteria to justify further investment. Accordingly, during the third quarter of
2001, Devon recorded a $10 million charge associated with the impairment of this
property. The after-tax effect of this reduction was $7 million.

During the first nine months of 2001, Devon elected to discontinue
operations in Thailand, Malaysia, Qatar and on certain properties in Brazil.
After meeting the drilling and capital commitments on these properties, Devon
determined that these properties did not meet Devon's internal criteria to
justify further investment. Accordingly, during the first nine months of 2001,
Devon recorded an $87 million charge associated with the impairment of these
properties. The after-tax effect of this reduction was $69 million.

INTEREST EXPENSE. Interest expense increased $94 million and $297
million, or 261% and 283%, in the third quarter and first nine months of 2002,
respectively, due to an increase in the average debt balance outstanding. The
average debt balance increased from $2.0 billion in third quarter of 2001 to
$7.9 billion in the 2002 quarter. The average debt balance increased from $1.9
billion in the first nine months of 2001 to $8.4 billion in the first nine
months of 2002. The increase in the average debt balance in the 2002 periods
caused interest expense to increase $92 million and $289 million in the third
quarter and first nine months of 2002, respectively. This increase was primarily
attributable to the long-term debt issued to complete the Anderson and Mitchell
acquisitions.

The average interest rate on outstanding debt decreased from 6.5% in
the 2001 quarter to 6.2% in the 2002 quarter and from 6.7% in the first nine

35

months of 2001 to 6.0% in the first nine months of 2002 due to the favorable
rates on the borrowings under the $3 billion term loan credit facility. This
facility's rates averaged less than 3% during the 2002 periods. The overall rate
decrease caused interest expense to decrease $1 million and $11 million in the
third quarter and first nine months of 2002, respectively. Other items included
in interest expense that are not related to the debt balance outstanding were $3
million and $19 million higher in the third quarter and first nine months of
2002, respectively. Of the $19 million increase in other items during the first
nine months of 2002, $8 million related to the early extinguishment of the 8.75%
senior notes. Items not related to the balance of debt outstanding include early
retirement penalties, facility and agency fees, amortization of costs and other
miscellaneous items.

The following schedule includes the components of interest expense for
the third quarter and first nine months of 2002 and 2001.

EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES. As a result of
the Anderson acquisition, Devon's Canadian subsidiary has $400 million of
fixed-rate senior notes which are denominated in U.S. dollars. Changes in the
exchange rate between the U.S. dollar and the Canadian dollar from the dates the
notes were acquired to the dates of repayment increase or decrease the expected
amount of Canadian dollars eventually required to repay the notes. Such changes
in the Canadian dollar equivalent balance of the debt are required to be
included in determining net earnings for the period in which the exchange rate
changes. The decrease in the Canadian-to-U.S. dollar exchange rate from $0.6585
at June 30, 2002 to $0.6306 at September 30, 2002 resulted in a $17 million loss
in the third quarter of 2002. The September 30, 2002 exchange rate was
substantially unchanged from the December 31, 2001 rate. Therefore, there was no
gain or loss recorded for the nine months ended September 30, 2002.

INCOME TAXES. During interim periods, income tax expense is based on
the estimated effective income tax rate that is expected for the entire fiscal
year. The estimated effective tax rate (tax expense divided by pre-tax earnings)
in the third quarter of 2002 was 25% compared to 39% in the third quarter of
2001. The estimated effective tax rate was a benefit of 83% in the first nine
months of 2002 compared to an expense of 40% in the first nine months of 2001.
Excluding the effect of the reduction of carrying value of Canadian oil and gas
properties, the effective tax rate was 24% in the first nine months of 2002.

36

The 2002 rates, excluding the Canadian writedown, were lower than the
statutory federal tax rate primarily due to the tax benefits of certain foreign
deductions. The 2001 rates were higher than the statutory federal tax rate due
to the effect of state taxes, goodwill amortization that was not deductible for
income tax purposes and the effect of foreign income taxes.

Statement of Financial Accounting Standards No. 109, Accounting for
Income Taxes ("SFAS No. 109"), requires that the tax benefit of available tax
carryforwards be recorded as an asset to the extent that management assesses the
utilization of such carryforwards to be "more likely than not". When the future
utilization of some portion of the carryforwards is determined not to be "more
likely than not", SFAS No. 109 requires that a valuation allowance be provided
to reduce the recorded tax benefits from such assets.

Included as deferred tax assets at September 30, 2002, were
approximately $157 million of tax related carryforwards. The carryforwards
include U.S. federal net operating loss carryforwards, the majority of which do
not begin to expire until 2008, U.S. state net operating loss carryforwards
which expire primarily between 2002 and 2014, Canadian carryforwards which
expire primarily between 2002 and 2008 and minimum tax credits which have no
expiration. Devon expects the tax benefits from the net operating loss
carryforwards to be utilized between 2002 and 2010. 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,
Devon's management believes that future taxable income will more likely than not
be sufficient to utilize substantially all its tax carryforwards prior to their
expirations.

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE. On January 1,
2001, Devon adopted SFAS No. 133, Accounting for Derivative Instruments and
Certain Hedging Activities, Devon recorded a net-of-tax cumulative-effect-type
adjustment to net earnings of $49 million gain related to the fair value of
derivatives that do not qualify as hedges. This gain included $46 million
related to the option embedded in the debentures that are exchangeable into
shares of ChevronTexaco Corporation common stock.

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 Part 1, Item 1.

CAPITAL EXPENDITURES. Approximately $3.0 billion was spent in the first
nine months of 2002 for capital expenditures. This total includes $1.7 billion
related to the January 2002 Mitchell acquisition; $1.2 billion for other
acquisitions and the drilling or development of oil and gas properties; and $0.1
billion related to marketing and midstream assets. These amounts compare to
capital expenditures of $1.3 billion (substantially all of which was related to
the acquisition, drilling or development of oil and gas properties) in the first
nine months of 2001.

37

OTHER CASH USES. Devon's common stock dividends were $23 million and
$20 million in the first nine months of 2002 and 2001, respectively. Devon also
paid $7 million of preferred stock dividends in each of the first nine months of
2002 and 2001.

CAPITAL RESOURCES AND LIQUIDITY. Devon's primary source of liquidity
has historically been net cash provided by operating activities ("operating cash
flow"). This source has been supplemented as needed by accessing credit lines
and commercial paper markets and issuing equity securities and long-term debt
securities. In 2002, another major source of liquidity has been sales of oil and
gas properties.

Net cash provided by operating activities ("operating cash flow")
continued to be a primary source of capital and liquidity in the first nine
months of 2002. Operating cash flow in the first nine months of 2002 was $1.2
billion, compared to $1.5 billion in the first nine months of 2001. The decrease
in operating cash flow in the first nine months of 2002 was primarily caused by
the decline in commodity prices and increased expenses, as discussed earlier in
this section.

Devon's operating cash flow is sensitive to many variables, the most
volatile of which is pricing of the oil, natural gas and NGLs produced. Prices
for these commodities are determined primarily by prevailing market conditions.
Regional and worldwide economic conditions, weather and other substantially
variable factors influence market conditions for these products. These factors
are beyond Devon's control and are difficult to predict.

To mitigate some of the risk inherent in oil and natural gas prices,
Devon has entered into various fixed-price physical delivery contracts and
financial price swap contracts to fix the price to be received for a portion of
future oil and natural gas production. Additionally, Devon has utilized price
collars to set minimum and maximum prices on a portion of its production. The
table below provides the volumes associated with these various arrangements as
of September 30, 2002.

For the years 2005 through 2011, Devon has fixed-price physical
delivery contracts covering Canadian natural gas production ranging from 8 Bcf
to 14 Bcf per year. Thereafter, Devon also has Canadian gas volumes subject to
fixed-price contracts in the years from 2012 through 2016, but the yearly
volumes are less than 1 Bcf.

By removing the price volatility from the above volumes of oil and
natural gas production, Devon has mitigated, but not eliminated, the potential
negative effect of declining prices on its operating cash flow.

38

Other sources of liquidity are Devon's revolving lines of credit. On
June 7, 2002, Devon renewed the $800 million, 364-day portion of its unsecured
long-term credit facilities (the "Credit Facilities"). The Credit Facilities
include a U.S. facility of $725 million (the "U.S. Facility") and a Canadian
facility of $275 million (the "Canadian Facility").

Amounts borrowed under the Credit Facilities bear interest at various
fixed rate options that Devon may elect for periods up to six months. Such rates
are generally less than the prime rate. Devon may also elect to borrow at the
prime rate. The Credit Facilities provide for an annual facility fee of $1.4
million that is payable quarterly.

The $725 million U.S. Facility consists of a Tranche A facility of $200
million and a Tranche B facility of $525 million. The Tranche A facility matures
on October 15, 2004. Devon may borrow funds under the Tranche B facility until
June 5, 2003 (the "Tranche B Revolving Period"). Devon may request that the
Tranche B Revolving Period be extended an additional 364 days by notifying the
agent bank of such request between 30 and 60 days prior to the end of the
Tranche B Revolving Period. On June 6, 2003, at the end of the Tranche B
Revolving Period, Devon may convert the then outstanding balance under the
Tranche B facility to a two-year term loan by paying the Agent a fee of 12.5
basis points. The applicable borrowing rate would be at LIBOR plus 125 basis
points. On September 30, 2002, there were no borrowings outstanding under the
$725 million U.S. Facility. The available capacity under the U.S. Facility as of
September 30, 2002, net of commercial paper borrowings and outstanding letters
of credit, was $623 million.

Devon may borrow funds under the $275 million Canadian Facility until
June 5, 2003 (the "Canadian Facility Revolving Period"). Devon may request that
the Canadian Facility Revolving Period be extended an additional 364 days by
notifying the agent bank of such request between 30 and 60 days prior to the end
of the Canadian Facility Revolving Period. Debt outstanding as of the end of the
Canadian Facility Revolving Period is payable in semiannual installments of 2.5%
each for the following five years, with the final installment due five years and
one day following the end of the Canadian Facility Revolving Period. On
September 30, 2002, there were no borrowings under the $275 million Canadian
facility.

Under the terms of the Credit Facilities, Devon has the right to
reallocate up to $100 million of the unused Tranche B facility maximum credit
amount to the Canadian Facility. Conversely, Devon also has the right to
reallocate up to $100 million of unused Canadian Facility maximum credit amount
to the Tranche B Facility.

On July 25, 2002, Devon renewed and increased its letter of credit and
revolving bank facility ("LOC Facility") for its Canadian operations. This C$150
million LOC Facility will be used primarily by Devon's wholly-owned
subsidiaries, Devon Canada Corporation and Northstar Energy Corporation, to
issue letters of credit. As of September 30, 2002, C$105 million ($ 66 million
converted to U.S. dollars using the September 30, 2002 exchange rate) of letters
of credit were issued under the LOC Facility primarily for Canadian drilling
commitments.

Devon also has access to short-term credit under its commercial paper
program. Total borrowings under the U.S. Facility and the commercial paper
program may not exceed $725 million. Commercial paper debt generally has a
maturity of between seven to 90 days, although

39

it can have a maturity of up to 365 days. Devon had $78 million of commercial
paper debt outstanding at September 30, 2002, at an average interest rate of
2.3%.

A portion of cash used in the Anderson and Mitchell acquisitions was
provided by a $3 billion senior unsecured credit facility. This credit facility,
which was entered into in October 2001, has a term of five years. The $3 billion
credit facility was fully borrowed upon the closing of the Mitchell acquisition
on January 24, 2002. However, as of September 30, 2002, $1.9 billion of the
balance outstanding was retired. The primary sources of the repayments were the
issuance of $1 billion of debt securities, of which $0.8 billion was used to pay
down debt, and $1.1 billion from the sale of certain oil and gas properties.

The remaining balance outstanding as of September 30, 2002 will mature
as follows:

This $3 billion facility includes various rate options which can be
elected by Devon, including a rate based on LIBOR plus a margin. Through June
17, 2002, this margin was fixed at 100 basis points. Thereafter, the margin is
based on Devon's debt rating. Based on Devon's current debt rating, the margin
after June 17, 2002, is 100 basis points. As of September 30, 2002, the average
interest rate on this facility was 2.8%.

Devon's $1 billion revolving credit facilities and its $3 billion term
loan credit facility each contain only one material financial covenant. This
covenant requires Devon to maintain a ratio of total funded debt to total
capitalization of no more than 65%. The credit agreements contain definitions of
total funded debt and total capitalization that include adjustments to the
respective amounts reported in Devon's consolidated financial statements. Per
the agreements, total funded debt excludes the debentures that are exchangeable
into shares of ChevronTexaco Corporation common stock. Also, total
capitalization is adjusted to add back noncash financial writedowns such as full
cost ceiling property impairments or goodwill impairments. As of September 30,
2002, Devon's ratio of total funded debt to total capitalization, as defined in
its credit agreements, was 55.8%.

On March 25, 2002, Devon sold $1 billion of 7.95% notes due April 15,
2032. The net proceeds received, after discounts and issuance costs, were $986
million. The debt securities are unsecured and unsubordinated obligations of
Devon. The net proceeds were partially used to pay down $820 million on Devon's
$3 billion term loan credit facility. The remaining $166 million of net proceeds
was used in June 2002 to partially fund the early extinguishment of $175 million
of 8.75% senior notes due June 15, 2007. The notes were redeemed at 104.375% of
principal, or approximately $183 million.

During 2002, Devon estimates that it will sell certain oil and gas
properties (the "Disposition Properties") for between $1.4 billion and $1.5
billion. The Disposition Properties are predominantly those that are either
outside of Devon's core operating areas or otherwise do not fit Devon's current
strategic objectives. The Disposition Properties are located in the U.S., Canada
and International areas.

40

As of October 31, 2002, Devon has closed sales of Disposition
Properties totaling $1.4 billion in proceeds. In addition, Devon has identified
approximately $100 million of Disposition Properties that could be sold in the
fourth quarter of 2002.

A summary of Devon's contractual obligations as of September 30, 2002,
is provided in the following table.

Firm transportation agreements represent "ship or pay" arrangements
whereby Devon has committed to ship certain volumes of gas for a fixed
transportation fee. Devon has entered into these agreements to ensure that Devon
can get its gas production to market.

The above table does not include $90 million of letters of credit that
have been issued by commercial banks on Devon's behalf which, if funded, would
become borrowings under Devon's revolving credit facility. Most of these letters
of credit have been granted by Devon's financial institutions to support Devon's
Canadian drilling commitments. The $7.8 billion of long-term debt shown in the
table excludes $105 million of discounts included in the September 30, 2002,
book balance of the debt.

PROPERTY DIVESTITURES

During 2002, Devon estimates that it will sell certain oil and gas
properties (the "Disposition Properties") for between $1.4 billion and $1.5
billion. The Disposition Properties are predominantly those that are either
outside of Devon's core operating areas or otherwise do not fit Devon's current
strategic objectives. The Disposition Properties are located in the U.S., Canada
and International areas.

As of October 31, 2002, Devon has closed sales of Disposition
Properties totaling $1.4 billion in proceeds.

The Disposition Properties' actual contribution to Devon's 2002
operating results depends upon when the transactions to sell the Disposition
Properties closed. The following table presents the Disposition Properties'
quarterly operating results. No information is included in the following table
for fourth quarter 2002 due to the immaterial effect that any fourth quarter
sales are expected to have on Devon's results.

The following table includes production and expenses from International
Disposition Properties in Indonesia and Argentina. However, this is different
from the actual financial presentation that results from the divestiture of
these properties. Pursuant to Statement of

41

Financial Accounting Standards No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the International assets sold constitute a
"component of an entity." As such, in the period in which such International
properties are sold, the related operating results are reported as discontinued
operations. The prior periods' operating results related to such assets are also
reclassified and reported as discontinued operations. Therefore, upon the sale
of these International Disposition Properties, the individual historical amounts
for revenues and expenses of these properties have been netted and reported as
discontinued operations in the accompanying consolidated financial statements.
The results of the domestic and Canadian Disposition Properties are not
presented as discontinued operations due to significant continuing operations in
the United States and Canada.

42

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. SFAS No. 143 requires liability recognition for
retirement obligations associated with tangible long-lived assets, such as
producing well sites, offshore production platforms, and natural gas processing
plants. The obligations included within the scope of SFAS No. 143 are those for
which a company faces a legal obligation for settlement. The initial measurement
of the asset retirement obligation is to be fair value, defined as "the price
that an entity would have to pay a willing third party of comparable credit
standing to assume the liability in a current transaction other than in a forced
or liquidation sale." Devon expects that it will use a valuation technique such
as present value of expected cash outflows to estimate fair value.

The asset retirement cost equal to the fair value of the retirement
obligation is to be capitalized as part of the cost of the related long-lived
asset and allocated to expense using a systematic and rational method.

Devon will be required to adopt SFAS No. 143 effective January 1, 2003
using a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depreciation.

Devon currently includes estimated costs of dismantlement, removal,
site reclamation, and other similar activities in the total costs that are
subject to depreciation, depletion, and amortization. Devon does not record a
separate asset or liability for such amounts. Devon has not completed the
assessment of the impact that adoption of SFAS No. 143 will have on its
consolidated financial statements.

The FASB issued Statement No. 145, Rescission of FASB Statements No. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, on
April 30, 2002. SFAS No. 145 will be effective for fiscal years beginning after
May 15, 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses
From Extinguishment of Debt, and requires that all gains and losses from
extinguishment of debt should be classified as extraordinary items only if they
meet the criteria in APB No. 30. Applying APB No. 30 will distinguish
transactions that are part of an entity's recurring operations from those that
are unusual or infrequent or that meet the criteria for classification as an
extraordinary item. Any gain or loss on extinguishment of debt that was
classified as an extraordinary item in prior periods presented that does not
meet the criteria in APB No. 30 for classification as an extraordinary item must
be reclassified. Devon will adopt the provisions related to the rescission of
SFAS No. 4 as of January 1, 2003.

In 1999, Devon recorded a $4 million extraordinary loss related to the
early extinguishment of long-term debt. Upon adopting SFAS No. 145 in 2003, this
extraordinary loss will be reclassified as interest expense in any presentation
of Devon's results that includes the year 1999.

The FASB issued Statement No. 146, Accounting for Costs Associated with
Exit or Disposal Activities, in June 2002. SFAS No. 146 addresses financial
accounting and reporting for costs associated with exit or disposal activities
and nullifies Emerging Issues Task Force Issue No. 94-3, Liability Recognition
for Certain Employee Termination Benefits and Other Costs to Exit an Activity
(including Certain Costs incurred in a Restructuring). SFAS No. 146

43

applies to costs incurred in an "exit activity", which includes, but is not
limited to, a restructuring, or a "disposal activity" covered by SFAS No. 144.

SFAS No. 146 requires that a liability for a cost associated with an
exit or disposal activity be recognized when the liability is incurred.
Previously, under Issue 94-3, a liability for an exit cost was recognized at the
date of an entity's commitment to an exit plan. Statement No. 146 also
establishes that fair value is the objective for initial measurement of the
liability.

The provisions of SFAS No. 146 are effective for exit or disposal
activities that are initiated after December 31, 2002. Devon currently has no
such exit or disposal activities planned.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information included in "Quantitative and Qualitative Disclosures
About Market Risk" in Item 7A of Devon's 2001 Annual Report on Form 10-K, and
the update of such information included in Item 3 of Devon's Quarterly Report on
Form 10-Q for the period ended June 30, 2002, is incorporated herein by
reference. Such information includes a description of Devon's potential exposure
to market risks, including commodity price risk, interest rate risk and foreign
currency risk. As of September 30, 2002, there have been no material changes in
Devon's market risk exposure from that disclosed in the June 30, 2002 Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures and internal controls
designed to ensure that information required to be disclosed in our filings
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission's rules and forms. Our principal executive and financial officers
have evaluated our disclosure controls and procedures within 90 days prior to
the filing of this Quarterly Report on Form 10-Q and have determined that such
disclosure controls and procedures are effective.

Subsequent to their evaluation, there were no significant changes in
internal controls or other factors that could significantly affect internal
controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.

44

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

None

ITEM 2. CHANGES IN SECURITIES

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

ITEM 5. OTHER INFORMATION

None

45

ITEM 6.EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits required by Item 601 of Regulation S-K are as follows:

Exhibit No.

4.1 Second Supplemental Indenture, dated as of October 31,
2002, by and between Devon Energy Production Company,
L.P., as Successor to the Issuer, and The Bank of New
York, as Trustee supplementing the Indenture dated as
of June 1, 1999, as supplemented by the First
Supplemental Indenture, dated as of June 14, 1999, by
and between Devon SFS Operating, Inc. and the Trustee

99.1 Certification of J. Larry Nichols, Chief Executive
Officer of Registrant, pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

99.2 Certification of William T. Vaughn, Chief Financial
Officer of Registrant, pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002

(b) Reports on Form 8-K.

A Report on Form 8-K was filed August 14, 2002 to announce that
Devon's Chief Executive Officer and Chief Financial Officer,
each filed with the Securities and Exchange Commission a
statement under oath regarding facts and circumstances relating
to the accuracy of Devon's financial statements and each of
their consultations with Devon's Audit Committee, as required by
the Securities and Exchange Commission's "Order Requiring the
Filing of Sworn Statements Pursuant to Section 21(a)(1) of the
Securities Exchange Act of 1934" (File No. 4-460, June 27,
2002).

A Report on Form 8-K was filed October 3, 2002 to reclassify
Devon's Indonesian activities as discontinued operations
following the sale of those operations to PetroChina Company
Limited.

46

SIGNATURES

Pursuant to the requirements 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

Date: November 13, 2002 /s/ Danny J. Heatly
--------------------------------
Danny J. Heatly
Vice President - Accounting

47

CERTIFICATION

I, J. Larry Nichols, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Devon Energy
Corp.;

2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Date: November 13, 2002
/s/ J. Larry Nichols
----------------------------------
J. Larry Nichols
Chief Executive Officer

48

CERTIFICATION

I, William T. Vaughn, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Devon Energy
Corp.;

2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report;

4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date");
and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Date: November 13, 2002
/s/ William T. Vaughn
-------------------------------
William T. Vaughn
Chief Financial Officer

49

INDEX TO EXHIBITS