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 June 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 July 31, 2002, was 160,200,000.

1 of 441 total pages
(Exhibit Index is found at page 54)

DEVON ENERGY CORPORATION

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

Page No.
--------
Part I. Financial Information
Item 1. Consolidated Financial Statements

Consolidated Balance Sheets, June 30, 2002 (Unaudited) 4
and December 31, 2001

Consolidated Statements of Operations (Unaudited) 5
for the Three Months and Six Months Ended June 30, 2002
and 2001

Consolidated Statements of Comprehensive Operations 7
(Unaudited) for the Three Months and Six Months Ended
June 30, 2002 and 2001

Consolidated Statements of Cash Flows (Unaudited) 8
for the Six Months Ended June 30, 2002 and 2001

Notes to Consolidated Financial Statements 9

Item 2. Management's Discussion and Analysis of Financial 27
Condition and Results of Operations

Item 3. Quantitative and Qualitative Disclosures About Market
Risk 47

Part II. Other Information
Item 4. Submission of Matters to a Vote of Security Holders 51

Item 6. Exhibits and Reports on Form 8-K 52

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
JUNE 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)

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 OPERATIONS
(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 2001 Annual Report on Form 10-K.

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 June 30,
2002, and the results of their operations and their cash flows for the
three-month and six-month periods ended June 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.

9

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Anderson Exploration Ltd. Acquisition

On October 12, 2001, Devon accepted all of the Anderson common shares
tendered by Anderson stockholders in the tender offer, which represented
approximately 97% of the outstanding Anderson common shares. On October 17,
2001, Devon completed its acquisition of Anderson by a compulsory acquisition
under the Canada Business Corporations Act of the remaining 3% of Anderson
common shares. 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 six-month periods ended June 30, 2002 and 2001.
The information for the six-month periods ended June 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.

10

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 six-month period
ended June 30, 2001 include $17 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
will be 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 and the Mitchell merger.

11

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

12

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. LONG-TERM DEBT

$3 Billion Term Loan Credit Facility

Prior to December 31, 2001, Devon used proceeds of $1 billion of its $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 June 30, 2002, $1.7 billion of
the balance outstanding was retired. The primary sources of the repayments were
the issuance of $1 billion of debt securities discussed below and $896 million
from the sale of certain oil and gas properties. With the proceeds from
additional property sales through July 31, 2002, the term loan balance has been
further reduced by $153 million. The term loan's balance as of July 31, 2002,
was $1.1 billion.

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 June 30, 2002, Devon had $315 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 $315 million outstanding under the commercial paper program was
classified as long-term debt on the June 30, 2002 consolidated balance sheet.

13

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Amendment of Existing 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 June 30, 2002, there were no borrowings
outstanding under the $725 million U.S. Facility. The available capacity under
the U.S. Facility as of June 30, 2002, net of commercial paper borrowings, was
$410 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 June 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.

The agreements governing the Credit Facilities contain certain
covenants and restrictions, including a maximum allowed debt-to-capitalization
ratio as defined in the agreements.

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 July 31, 2002, C$104 million of letters of credit
were issued under the LOC Facility primarily for Canadian drilling commitments.

14

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 Canadian oil revenues that are
predominantly 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 June 30, 2002, $15 million of net deferred losses on derivative
instruments in "accumulated other comprehensive income (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 30 months.

Devon recorded in its statements of operations a gain of $24 million
and $7 million in the second quarter of 2002 and 2001, respectively, and a gain
of $7 million and a loss of $7 million in the six-month periods ended June 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 and six-month periods ended June 30, 2002 are net gains of
approximately $3 million and $10 million, respectively, related to such
ineffectiveness. These gains 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). 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

15

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 and six-month periods ended June 30, 2001. The diluted loss per
share calculations for the three-month and six-month periods ended June 30, 2002
produce results that are anti-dilutive. (The diluted calculation for the three
months ended June 30, 2002 reduced the net loss by $2 million and increased the
common shares outstanding by 6 million shares. The diluted calculation for the
six months ended June 30, 2002 reduced the net loss by $5 million and increased
the common shares outstanding by 6 million shares.) Therefore, the diluted loss
per share amounts for the three-month and six-month periods

16

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ended June 30, 2002 reported in the accompanying consolidated statements of
operations are the same as the basic loss per share amounts.

All options to purchase Devon common stock were excluded from the
diluted earnings per share calculations for the 2002 periods because of the
anti-dilutive effect of such options. Options to purchase approximately 1.0
million shares of Devon's common stock with exercise prices ranging from $56.76
per share to $89.66 per share (with a weighted average price of $65.31 per
share) were excluded from the diluted earnings per share calculation for the
second quarter of 2001.

Options to purchase approximately 1.0 million shares of Devon's common
stock, with exercise prices from $57.72 to $89.66 per share (with a weighted
average price of $65.34 per share) were excluded from the diluted earnings per
share calculation for the first six months of 2001.

17

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.
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, 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 $262 million. Devon received
approximately $250 million upon closing. An additional $12 million could be
received upon successful completion of certain events. In accordance with SFAS
No. 144, Devon has reclassified the assets, liabilities and results

18

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

of its Indonesian 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 six
months of 2002 and 2001 are presented below:

19

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

20

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. SEGMENT INFORMATION (CONTINUED)

21

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. SEGMENT INFORMATION (CONTINUED)

22

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. SEGMENT INFORMATION (CONTINUED)

23

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

10. SEGMENT INFORMATION (CONTINUED)

24

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 June 30, 2002, Devon's consolidated balance
sheet included $9 million of 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 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

25

DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

currently believe that it is subject to material exposure in association with
these lawsuits and no liability has been recorded in connection therewith.

Also, pending in federal court in Texas is a similar suit alleging
underpaid royalties to the United States in connection with natural gas and
natural gas liquids produced and sold from United States owned and/or controlled
lands. The claims were filed by private litigants against Devon and numerous
other producers, under the federal False Claims Act. The United States served
notice of its intent to intervene as to certain defendants, but not Devon. Devon
and certain other defendants are challenging the constitutionality of whether a
claim under the federal False Claims Act can be maintained absent government
intervention. Devon believes that it has acted reasonably and paid royalties in
good faith. Devon does not currently believe that it is subject to material
exposure in association with this litigation. As a result, Devon's monetary
exposure in this suit is not expected to be material.

26

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 six-month periods ended June 30, 2002,
compared to the three-month and six-month periods ended June 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 a net loss for the second quarter of 2002 of $104
million, or $0.68 per share. This compares to net earnings of $136 million, or
$1.03 per share for the second quarter of 2001. Net loss for the first half of
2002 was $42 million, or $0.31 per share. This compares to net earnings for the
first half of 2001 of $536 million, or $4.11 per share. The decrease in second
quarter and first half earnings was due to a decline in oil, natural gas and NGL
prices, increases in expenses and a $651 million reduction of carrying value of
Canadian oil and gas properties, the effects of which were partially offset by
an increase in production.

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. As of July 31, 2002, C$104 million of letters of credit
were issued under the LOC Facility primarily for Canadian drilling commitments.

27

RESULTS OF OPERATIONS

Total revenues increased $466 million, or 67%, in the second quarter of
2002, and $387 million, or 23%, in the first half 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 average prices of oil,
gas and NGLs. The increases in production and marketing and midstream revenue
were primarily the result of the Anderson and Mitchell acquisitions.

Oil, gas and NGL revenues were up $214 million, or 31%, for the second
quarter of 2002 compared to the second quarter of 2001, and were down $5 million
for the first half of 2002 compared to the first half of 2001. The three-month
and six-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.

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 six-month periods ended June 30, 2002 and 2001.

30

OIL REVENUES. Oil revenues increased $53 million, or 25%, in the second
quarter of 2002. An increase in 2002's production of 2 million barrels caused
oil revenues to increase by $61 million. The October 2001 Anderson acquisition
and the January 2002 Mitchell acquisition accounted for substantially all of the
increased production. The effects of the production increase were partially
offset by a $0.67 per barrel decrease in the average price of oil in 2002.

Oil revenues increased $68 million, or 16%, in the first half of 2002.
An increase in production of 6 million barrels, or 33%, caused oil revenues to
increase by $146 million. The Anderson and Mitchell acquisitions were primarily
responsible for the increased production. The effects of the production increase
were partially offset by a $3.22 per barrel decrease in the average price of oil
in 2002.

GAS REVENUES. Gas revenues increased $121 million, or 27%, in the
second quarter of 2002. An increase in production of 91 Bcf, or 84%, caused gas
revenues to increase by $372 million. The Anderson and Mitchell acquisitions
were primarily responsible for the increased production. The effects of the
production increase were partially offset by a $1.26 per Mcf decrease in the
average gas price in the second quarter of 2002.

Gas revenues decreased $136 million, or 12%, in the first half of 2002.
A $2.68 per Mcf decrease in the average gas price in the first half of 2002
caused revenues to decrease $592 million. The effects of the price decline were
partially offset by a production increase of 174 Bcf in the 2002 period. The
Anderson and Mitchell acquisitions accounted for substantially all of the
increased production.

NGL REVENUES. NGL revenues increased $40 million in the second quarter
of 2002. A 4 million barrel increase in 2002 production caused revenues to
increase $72 million. The Anderson and Mitchell acquisitions accounted for
substantially all of the increased production. The effects of the production
increase were partially offset by a $6.02 per barrel decrease in the average NGL
price in the second quarter of 2002.

NGL revenues increased $63 million in the first half of 2002. A 7
million barrel increase in 2002 production caused revenues to increase $149
million. The Anderson and Mitchell acquisitions were primarily responsible for
the increased production. The effects of the production increase were partially
offset by an $8.87 per barrel decrease in the average NGL price in the first
half of 2002.

MARKETING AND MIDSTREAM REVENUES. Marketing and midstream revenues
increased $252 million and $392 million in the second quarter and first half of
2002, respectively. The Mitchell acquisition included significant marketing and
midstream assets which accounted for the increase in revenues.

31

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

Lease operating expenses increased $59 million and $107 million in the
second quarter and first half of 2002, respectively. The Anderson and Mitchell
acquisitions accounted for $62 million and $123 million of the increases,
respectively. The historical Devon lease operating expenses decreased $3 million
and $16 million, respectively, due to lower fuel and electricity costs as well
as lower third-party field service costs.

Transportation costs increased $19 million and $40 million in the
second quarter and first half of 2002, respectively, primarily due to an
increase in gas production from the Anderson and Mitchell acquisitions and
increases in transportation costs per unit.

Production taxes increased $6 million in second quarter of 2002 and
decreased $17 million in the first half 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 3% increase and 25% decrease in domestic oil, gas and NGL
revenues in the second quarter and first half 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 $210 million and $319 million in the second quarter
and first half 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 $131 million, or 78%, from $169 million in the
second quarter of 2001 to $300 million in the second quarter of 2002. Oil and
gas property related DD&A expense increased $127 million due to the 72% increase
in combined oil, gas and NGLs production in 2002. Additionally, an increase in
the combined U.S., Canadian and international DD&A rate from $5.89 per Boe in
2001 to $5.97 per Boe in 2002 caused oil and gas property related DD&A to
increase by $4 million.

32

Oil and gas property related DD&A increased $257 million, or 76%, from
$337 million in the first half of 2001 to $594 million in the first half of
2002. Oil and gas property related DD&A expense increased $246 million due to
the 72% increase in combined oil, gas and NGLs production in 2002. Additionally,
an increase in the combined U.S., Canadian and international DD&A rate from
$5.84 per Boe in 2001 to $5.95 per Boe in 2002 caused oil and gas property
related DD&A to increase by $11 million.

Non-oil and gas property DD&A expense increased $16 million from $11
million in the second quarter of 2001 compared to $27 million the second quarter
of 2002. Non-oil and gas property DD&A expense increased $29 million from $20
million in the first half of 2001 compared to $49 million the first half of
2002. Depreciation of the marketing and midstream assets acquired in the January
2002 Mitchell acquisitions accounted for 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 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 second quarter and first half of 2002 and 2001.

Net G&A increased $28 million and $55 million, or 108% and 112%, in the
second quarter and first half of 2002 compared to the same periods of 2001,
respectively. Gross G&A increased $38 million and $78 million, or 62% and 70%,
in the second quarter and first half of 2002 compared to the same periods of
2001, respectively. The increase in gross expenses in both periods of 2002 was
primarily related to the Anderson and Mitchell acquisitions.

Capitalized G&A increased $4 million and $10 million in the second
quarter and first half of 2002, respectively. Reimbursed G&A increased $6
million and $13 million in the second quarter and first half 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

33

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. 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 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, 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, 2002.

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 second quarter of 2001, Devon elected to discontinue
operations in Malaysia, Qatar and on certain properties in Brazil. Accordingly,
during the second quarter of 2001, Devon recorded a $77 million charge
associated with the impairment of these properties. The after-tax effect of this
reduction was $62 million.

INTEREST EXPENSE. Interest expense increased $113 million and $203
million, or 323% and 294%, in the second quarter and first half of 2002,
respectively, due to an increase in the average debt balance outstanding. The
average debt balance increased from $1.9 billion in second quarter

34

of 2001 to $8.9 billion in the 2002 quarter. The average debt balance increased
from $1.9 billion in the first half of 2001 to $8.6 billion in the first half of
2002. The increase in the average debt balance in the 2002 periods caused
interest expense to increase $106 million and $196 million in the second quarter
and first half 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 6.8% in
the 2001 quarter to 6.0% in the 2002 quarter and from 6.8% in the first half of
2001 to 5.9% in the first half 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 $3 million and $8 million in the second quarter and
first half of 2002, respectively. Other items included in interest expense that
are not related to the debt balance outstanding were $10 million and $15 million
higher in the second quarter and first half of 2002, respectively. Of this
increase, $8 million related to the early extinguishment of 8.75% senior notes.
Items not related to the balance of debt outstanding include facility and agency
fees, amortization of costs and other miscellaneous items.

The following schedule includes the components of interest expense for
the second quarter and first half of 2002 and 2001.

EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES. The devaluation
of the Argentine peso resulted in a $3 million and $6 million loss in the second
quarter and first half 2002, respectively. Additionally, 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
increase in the Canadian-to-U.S. dollar exchange rate from $0.6275 at March 31,
2002 to $0.6585 at June 30, 2002 resulted in a $19 million gain in the second
quarter of 2002. The increase in the Canadian-to-U.S. dollar exchange rate from
$0.6279 at December 31, 2001 to $0.6585 at June 30, 2002 resulted in an $18
million gain in the first half of 2002.

35

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 in the second quarter of 2002 was a
benefit of 53% compared to an expense of 43% in the second quarter of 2001. The
estimated effective tax rate was a benefit of 59% in the first half of 2002
compared to an expense of 40% in the first half of 2001. Excluding the effect of
the reduction of carrying value of Canadian oil and gas properties, the
effective tax rate was 24% and 25% in the second quarter and first half of 2002,
respectively.

The 2002 rate, excluding the Canadian writedown, was lower than the
statutory federal tax rate primarily due to the tax benefits of certain foreign
deductions. The 2001 rate was 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 June 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. Upon adoption, 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.

36

CAPITAL EXPENDITURES. Approximately $2.6 billion was spent in the first
six months of 2002 for capital expenditures. This total includes $1.7 billion
related to the January 2002 Mitchell acquisition and $0.8 billion for the
acquisition, drilling or development of oil and gas properties. These amounts
compare to first half 2001 capital expenditures of $1.0 billion ($1.0 billion of
which was related to oil and gas properties).

OTHER CASH USES. Devon's common stock dividends were $16 million and
$13 million in the first half of 2002 and 2001, respectively. Devon also paid $5
million of preferred stock dividends in each of the first six 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 half of
2002. Operating cash flow in the first half of 2002 was $896 million, compared
to $1.1 billion in the first half of 2001. The decrease in operating cash flow
in the first half 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 July 31, 2002.

For the years 2005 through 2011, Devon has fixed-price physical delivery
contracts covering Canadian natural gas production ranging from 10 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.

37

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.

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 June 30, 2002, there were no borrowings outstanding under the $725
million U.S. Facility. The available capacity under the U.S. Facility, net of
commercial paper borrowings as of June 30, 2002, was $410 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 June 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 July 31, 2002, C$104 million 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

38

million. Commercial paper debt generally has a maturity of between seven to 90
days, although it can have a maturity of up to 365 days. Devon had $315 million
of commercial paper debt outstanding at June 30, 2002, at an 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 June 30, 2002, $1.7 billion of the balance
outstanding was retired. The primary sources of the repayments were the issuance
of $1 billion of debt securities discussed below and $896 million from the sale
of certain oil and gas properties. With the proceeds from additional property
sales through July 31, 2002, the term loan balance has been further reduced by
$153 million. The term loan's balance as of July 31, 2002, was $1.1 billion.

The remaining balance outstanding as of July 31, 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 August 1, 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 70% through June 30, 2002, and no more than 65%
thereafter. 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 June 30, 2002, Devon's ratio of total funded debt to
total capitalization, as defined in its credit agreements, was 56.1%.

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 $1.3 billion and $1.6
billion. The Disposition Properties

39

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 July 31, 2002, Devon has closed sales of Disposition Properties
totaling $1.3 billion in proceeds. In addition, Devon has identified another
$200 million to $300 million of Disposition Properties that could be sold in the
second half of the year.

A summary of Devon's contractual obligations as of June 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. Devon expects to have sufficient volumes
to ship to satisfy the firm transportation agreements, so that Devon will be
receiving equivalent value for the firm transportation payments that it will
make.

The above table does not include $99 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 $8.1 billion of long-term debt shown in the
table excludes $105 million of discounts included in the June 30, 2002, book
balance of the debt.

REVISIONS TO 2002 ESTIMATES

On May 15, 2002, Devon filed a Form 10-Q that provided forward-looking
estimates for the full year 2002. Revisions to certain of those previous
estimates are provided herein to reflect actual year-to-date results.

YEAR 2002 POTENTIAL OPERATING ITEMS

The estimates related to oil, gas and NGL production, operating costs
and DD&A set forth in the following paragraphs are based on estimates for
Devon's properties other than those that have been designated for possible sale
(See "Property Acquisitions and Divestitures"). Therefore, the following
estimates exclude the results of the potential sale properties for the entire
year. Also, all of the estimates related to price swaps and costless price
collars are as of July 31, 2002.

40

OIL, GAS AND NGL PRODUCTION Set forth in the following paragraphs are
individual estimates of Devon's oil, gas and NGL production for 2002. On a
combined basis, Devon estimates its 2002 oil, gas and NGL production will total
between 173.8 and 182.9 MMBoe. Of this total, approximately 92% is estimated to
be produced from reserves classified as proved at December 31, 2001.

OIL PRODUCTION Devon expects its oil production to total between 36.2
and 38.1 MMBbls. Of this total, approximately 95% is estimated to be produced
from reserves classified as proved at December 31, 2001. The expected ranges of
production by area are as follows:

OIL PRICES - FIXED Through certain forward oil sales agreements assumed
in the 2000 Santa Fe Snyder merger, the price on a portion of Devon's 2002 oil
production has been fixed. These agreements fixed the price on 2.5 MMBbls of
2002 oil production at an average price of $16.84 per Bbl. It should be noted
that these forward sales apply only to production in the first eight months of
2002.

Devon has executed price swaps attributable to 8 MMBbls of domestic
production at an average price of $23.85 per Bbl. Additionally, Devon has
entered into price swaps attributable to Canadian production of 1.6 MMBbls at an
average price of $20.33 per Bbl.

OIL PRICES - FLOATING For oil production for which prices have not been
fixed, Devon's average prices are expected to differ from the NYMEX price as set
forth in the following table.

Devon has also entered into costless price collars that set a floor
price and a ceiling price for 7.3 MMBbls of United States oil production that
otherwise is subject to floating prices. The collars have weighted average floor
and ceiling prices per Bbl of $23.00 and $28.19, respectively. The floor and
ceiling prices are based on the NYMEX price. The NYMEX price is the monthly
average of settled prices on each trading day for West Texas Intermediate Crude
oil delivered at Cushing, Oklahoma. If the NYMEX price is outside of the ranges
set by the floor and ceiling prices in the various collars, Devon and the
counterparty to the collars will settle the difference. Any such settlements
will either increase or decrease Devon's oil revenues for the period. Because
Devon's oil volumes are often sold at prices that differ from the NYMEX price
due to differing quality (i.e., sweet crude versus sour crude) and
transportation costs from different geographic areas, the floor and ceiling
prices of the various collars do not reflect actual limits of Devon's realized
prices for the production volumes related to the collars.

41

GAS PRODUCTION Devon expects its gas production to total between 720
Bcf and 758 Bcf. Of this total, approximately 90% is estimated to be produced
from reserves classified as proved at December 31, 2001. The expected ranges of
production are as follows:

GAS PRICES - FIXED Through various price swaps and fixed-price physical
delivery contracts, Devon has fixed the price it will receive on a portion of
its natural gas production. The following tables include information on this
fixed-price production. Where necessary, the prices have been adjusted for
certain transportation costs that are netted against the prices recorded by
Devon, and the prices have also been adjusted for the Btu content of the gas
hedged.

GAS PRICES - FLOATING For the natural gas production for which prices
have not been fixed, Devon's average prices are expected to differ from the
NYMEX price as set forth in the following table. The NYMEX price is determined
to be the first-of-month South Louisiana Henry Hub price index as published
monthly in Inside FERC.

Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its natural gas production that otherwise is
subject to floating prices. If the applicable monthly price indices are outside
of the ranges set by the floor and ceiling prices in the various collars, Devon
and the counterparty to the collars will settle the difference. Any such
settlements will either increase or decrease Devon's gas revenues for the
period. Because Devon's gas volumes are often sold at prices that differ from
the related regional indices, and due to differing Btu contents of gas produced,
the floor and ceiling prices of the various collars do not reflect actual limits
of Devon's realized prices for the production volumes related to the collars.

Devon has entered into costless collars concerning its 2002 gas
production. To simplify presentation, these collars have been aggregated in the
following table according to similar floor prices. The floor and ceiling prices
shown are weighted averages of the various collars in each aggregated group.

The prices shown in the following table have been adjusted to a
NYMEX-based price, using Devon's estimates of 2002 differentials between NYMEX
and the specific regional indices upon which the collars are based. The floor
and ceiling prices related to the domestic collars are based on various regional
first-of-the-month price indices as published monthly by Inside FERC. The floor
and ceiling prices related to the Canadian collars are based on the AECO index
as published by the Canadian Gas Price Reporter.

42

NGL PRODUCTION Devon expects its production of NGLs to total between
17.6 million barrels and 18.5 million barrels. Of this total, 98% is estimated
to be produced from reserves classified as proved at December 31, 2001. The
expected ranges of production are as follows:

MARKETING AND MIDSTREAM REVENUES AND EXPENSES Devon estimates that 2002
marketing and midstream revenues will be between $966 million and $999 million
and marketing and midstream expenses will be between $800 million and $826
million.

DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A") Devon expects its
DD&A expense related to non-oil and gas property fixed assets to total between
$100 million and $104 million. This range includes $64 million to $68 million
related to marketing and midstream assets.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A") Devon estimates that
consolidated G&A will be between $200 million and $210 million.

INCOME TAXES Devon estimates that its consolidated financial income tax
rate in 2002 will be between 20% and 40%. The current income tax rate is
expected to be between 15% and 25%. The deferred income tax rate is expected to
be between 5% and 15%. These rates exclude the effects of the Canadian writedown
and property sales as discussed in the following paragraph.

The preceding estimated rates exclude the effect of the second quarter
2002 Canadian reduction of carrying value of oil and gas properties. This
reduction resulted in a reduction of pretax income $651 million and a deferred
tax benefit of $267 million. These estimated tax rates also exclude the effects
of domestic property sales. These domestic property sales result in gains for
tax purposes, but there is no corresponding financial gain or loss because Devon
follows the full-cost method of accounting. As a result, 2002 current taxes are
expected to be increased from $105 million to $115 million for these domestic
property sales and deferred taxes are expected to be decreased by the same
amount.

REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES Devon follows the
full cost method of accounting for its oil and gas properties. Under the full
cost method, Devon's net

43

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 lower of cost or fair value of unproved
properties. The ceiling is imposed separately by country. In calculating future
net revenues, current prices and costs are generally held constant indefinitely.
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.

Because the ceiling calculation dictates that prices in effect as of
the last day of the applicable quarter are held constant indefinitely, the
resulting value is not indicative of the true fair value of the reserves. Oil
and natural gas prices have historically been cyclical and, on any particular
day at the end of a quarter, can be either substantially higher or lower than
Devon's long-term price forecast that is a barometer for true fair value.
Therefore, oil and gas property writedowns that result from applying the full
cost ceiling limitation, and that are caused by fluctuations in price as opposed
to reductions to the underlying quantities of reserves, should not be viewed as
absolute indicators of a reduction of the ultimate value of the related
reserves.

Devon recorded writedowns to its Canadian oil and gas properties as of
June 30, 2002, after Canadian gas prices dropped sharply during the last half of
June 2002. The June 30, 2002, reference prices used in the Canadian ceiling
calculation, expressed in Canadian dollars, were a NYMEX price of C$40.79 per
barrel of oil and an AECO price of C$2.17 per Mcf of gas. Volatility of oil and
gas prices prevents an accurate estimate of whether additional writedowns will
occur in future periods.

PROPERTY ACQUISITIONS AND DIVESTITURES Though Devon has completed
several major property acquisitions in recent years, these transactions are
opportunity driven. Thus, Devon does not "budget," nor can it reasonably
predict, the timing or size of such possible acquisitions, if any, other than
the Mitchell acquisition closed on January 24, 2002.

During 2002, Devon estimates that it will sell certain oil and gas
properties (the "Disposition Properties") for between $1.3 billion and $1.6
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 July 31, 2002, Devon has closed sales of Disposition Properties
totaling $1.3 billion in proceeds. In addition, Devon has identified another
$200 million to $300 million of Disposition Properties that could be sold in the
second half of 2002.

The estimates of Devon's 2002 results previously set forth in this
report and previous reports exclude any results from the Disposition Properties.
The Disposition Properties' actual contribution to Devon's 2002 operating
results will depend upon when the transactions to sell the Disposition
Properties are actually closed. The following table presents Devon's estimates
of the Disposition Properties' quarterly operating results. The table also
includes estimated third quarter operating results of the $200 to $300 million
of various Disposition Properties that, if sold, are expected to close during
the second half of 2002.

44

The following table includes production and expense estimates from
International Disposition Properties. However, if and when these properties are
ultimately sold, the financial presentation of the related operating results
will differ. Pursuant to Statement of Financial Accounting Standards No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets, the
International assets to be 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 will also be 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 are netted and reported as discontinued operations.
The results of the domestic and Canadian Disposition Properties will not be
presented as discontinued operations due to significant continuing operations in
the United States and Canada.

45

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
expected present value 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 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.

46

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.

Emerging Issues Task Force Topic 2-03, "Recognition and Reporting of
Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," and No. 00-17, "Measuring the Fair Value of Energy-Related
Contracts in Applying Issue No. 98-10" was issued in June 2002. The Task Force
reached a consensus that all mark-to-market gains and losses on energy trading
contracts should be shown net in the income statement whether or not settled
physically. Companies would be required to disclose the gross transaction
volumes for those energy trading contracts that are physically settled. The
consensus is effective for financial statements issued for periods ending after
July 15, 2002. Upon application of the consensus, comparative financial
statements for prior periods are required to be reclassified to conform to the
consensus. Devon has not engaged in material energy trading and risk management
activities. Rather Devon has engaged in the marketing of Devon's and third party
oil and gas. Should Devon be required to adopt the provisions of EITF 2-03, the
result would have reduced gathering, marketing, and processing revenues and
expenses. The adoption of the consensus would not have an effect on Devon's net
results from operations.

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 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. The following information updates
Devon's commodity price risk exposure as of July 31, 2002, for changes from that
disclosed in the 2001 Form 10-K.

COMMODITY PRICE RISK Devon's major market risk exposure is in the
pricing applicable to its oil and gas production. Realized pricing is primarily
driven by the prevailing worldwide price for crude oil and spot market prices
applicable to its U.S. and Canadian natural gas production. Pricing for oil and
gas production has been volatile and unpredictable for several years.

Devon periodically enters into financial hedging activities with
respect to a portion of its projected oil and natural gas production through
various financial transactions which hedge the future prices received. These
transactions include financial price swaps whereby Devon will receive a fixed
price for its production and pay a variable market price to the contract
counterparty, and costless price collars that set a floor and ceiling price for
the hedged production. If the applicable monthly price indices are outside of
the ranges set by the floor and ceiling prices in the various collars, Devon and
the counterparty to the collars will settle the difference. These financial
hedging activities are intended to support oil and natural gas prices at
targeted levels and to manage Devon's exposure to oil and gas price
fluctuations. Devon does not hold or issue derivative instruments for trading
purposes.

47

Devon's total hedged positions as of July 31, 2002 are set forth in the
following tables.

PRICE SWAPS Through various price swaps, Devon has fixed the price it
will receive on a portion of its oil and natural gas production in 2002, 2003
and 2004. The following tables include information on this production. Where
necessary, the prices have been adjusted for certain transportation costs that
are netted against the price recorded by Devon, and the price has also been
adjusted for the Btu content of the gas production that has been hedged.

COSTLESS PRICE COLLARS Devon has also entered into costless price
collars that set a floor and ceiling price for a portion of its 2002 and 2003
oil and natural gas production. The following tables include information on
these collars for each geographic area. The floor and ceiling prices related to
domestic oil production are based on NYMEX. The NYMEX price is the monthly
average of settled prices on each trading day for West Texas Intermediate Crude
oil delivered at Cushing, Oklahoma. The gas prices shown in the following table
have been adjusted to a NYMEX-based price, using Devon's estimates of
differentials between NYMEX and the specific regional indices upon which the
collars are based. The floor and ceiling prices related to the domestic collars
are based on various regional first-of-the-month price indices as published
monthly by Inside FERC. The floor and ceiling prices related to the Canadian
collars are based on the AECO index as published by the Canadian Gas Price
Reporter.

If the applicable monthly price indices are outside of the ranges set
by the floor and ceiling prices in the various collars, Devon and the
counterparty to the collars will settle the difference. Any such settlements
will either increase or decrease Devon's gas revenues for the period. Because
Devon's gas volumes are often sold at prices that differ from the related
regional indices, and due to differing Btu content of gas production, the floor
and ceiling prices of the various collars do not reflect actual limits of
Devon's realized prices for the production volumes related to the collars.

The floor and ceiling prices in the following tables are weighted
averages of all the collars.

48

FIXED-PRICE PHYSICAL DELIVERY CONTRACTS In addition to the commodity
hedging instruments described above, Devon also manages its exposure to oil and
gas price risks by periodically entering into fixed-price contracts.

The price Devon will receive on a portion of its 2002 oil production
has been fixed through certain forward oil sales assumed in the 2000 Santa Fe
Snyder merger. From January

49

2002 through August 2002, 311,000 barrels of oil production per month have been
fixed at an average price of $16.84 per barrel.

For each of the years 2002 through 2011, Devon has fixed-price gas
contracts that cover approximately 51 Bcf, 16 Bcf, 16 Bcf, 14 Bcf, 14 Bcf, 14
Bcf, 14 Bcf, 14 Bcf, 12 Bcf and 10 Bcf, respectively, of Canadian production.
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.

50

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

(a) Devon's annual meeting of stockholders was held in Oklahoma
City, Oklahoma at 10:00 a.m. local time, on Thursday May 16,
2002.

(b) Proxies for the meeting were solicited pursuant to Regulation
14 under the Securities Exchange Act of 1934, as amended.
There was no solicitation in opposition to the nominees for
election as directors as listed in the proxy statement and all
nominees were elected.

(c) Out of a total of 156,126,700 shares of Devon's common stock
outstanding and entitled to vote, 143,263,196 shares were
present at the meeting in person or by proxy, representing
approximately 92 percent of the total outstanding. The only
matter voted upon at the meeting was the election of four
directors to serve on Devon's board of directors until the
2005 annual meeting of stockholders. The vote tabulation with
respect to each nominee was as follows:

ITEM 5. OTHER INFORMATION

None

51

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

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

Exhibit No.

10.1 Seventh Amendment to U.S. Credit Agreement
dated June 7, 2002 by and among Registrant,
Bank of America, N.A., individually and as
administrative agent, and the U.S. Lenders
party to this Amendment

10.2 Amended and Restated Canadian Credit
Agreement dated June 7, 2002 among
Northstar Energy Corporation and Devon
Canada Corporation, as Canadian Borrowers,
Bank of America, N.A. acting through its
Canadian Branch, as Administrative Agent,
and Certain Financial Institutions, as
Lenders

10.3 Credit Agreement dated July 25, 2002, by
and among Northstar Energy Corporation and
Devon Canada Corporation, as Borrowers and
RBC Capital Markets, as Arranger and Royal
Bank of Canada, as Administrative Agent and
Certain Financial Institutions, as Lenders
for the Cdn. $140 million credit facility

10.4 Letter Agreement dated July 25, 2002, by
and among Northstar Energy Corporation and
Devon Canada Corporation, as Borrowers and
Royal Bank of Canada acting through its
Canadian Branch , as Lender for the Cdn.
$10 million credit facility

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

52

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

53

INDEX TO EXHIBITS