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<SEC-DOCUMENT>0000950134-03-003538.txt : 20030307
<SEC-HEADER>0000950134-03-003538.hdr.sgml : 20030307
<ACCEPTANCE-DATETIME>20030307131435
ACCESSION NUMBER: 0000950134-03-003538
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 11
CONFORMED PERIOD OF REPORT: 20021231
FILED AS OF DATE: 20030307
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: DEVON ENERGY CORP/DE
CENTRAL INDEX KEY: 0001090012
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 731567067
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 000-30176
FILM NUMBER: 03595811
BUSINESS ADDRESS:
STREET 1: 20 N BROADWAY
STREET 2: STE 1500
CITY: OKLAHOMA CITY
STATE: OK
ZIP: 73102
BUSINESS PHONE: 4052353611
MAIL ADDRESS:
STREET 1: 20 N BROADWAY
STREET 2: STE 1500
CITY: OKLAHOMA CITY
STATE: OK
ZIP: 73102
FORMER COMPANY:
FORMER CONFORMED NAME: DEVON DELAWARE CORP
DATE OF NAME CHANGE: 19990707
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>d03660e10vk.txt
<DESCRIPTION>FORM 10-K
<TEXT>
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
<Table>
<C> <S>
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 000-30176
</Table>
DEVON ENERGY CORPORATION
(Exact name of Registrant as Specified in its Charter)
<Table>
<S> <C>
DELAWARE 73-1567067
(State or Other Jurisdiction of Incorporation or (I.R.S. Employer Identification No.)
Organization)
20 NORTH BROADWAY, OKLAHOMA CITY, OKLAHOMA 73102-8260
(Address of Principal Executive Offices) (Zip Code)
</Table>
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(405) 235-3611
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
<Table>
<Caption>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
<S> <C>
Common Stock, par value $.10 per share American Stock Exchange
4.9% Convertible Debentures, due 2008 The New York Stock Exchange
4.95% Convertible Debentures, due 2008 The New York Stock Exchange
</Table>
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. [X] Yes No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). [X] Yes No [ ]
The aggregate market value of the voting stock held by non-affiliates of
the Registrant as of June 28, 2002, was $7,639,933,692.
On March 1, 2003, 155,195,958 shares of common stock and 1,680,637
exchangeable shares of Devon's wholly-owned subsidiary, Northstar Energy
Corporation, were outstanding. Each exchangeable share is exchangeable for one
share of Devon common stock.
DOCUMENTS INCORPORATED BY REFERENCE
None
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE>
TABLE OF CONTENTS
<Table>
<Caption>
PAGE
----
<S> <C> <C>
PART I
Item 1. Business.................................................... 5
Item 2. Properties.................................................. 13
Item 3. Legal Proceedings........................................... 22
Item 4. Submission of Matters to a Vote of Security Holders......... 22
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 22
Item 6. Selected Financial Data..................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 27
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 59
Item 8. Financial Statements and Supplementary Data................. 63
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 127
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 127
Item 11. Executive Compensation...................................... 133
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 138
Item 13. Certain Relationships and Related Transactions.............. 141
Item 14. Controls and Procedures..................................... 141
PART IV
Item 15. Exhibits, Financial Statements and Schedules, and Reports on
Form 8-K.................................................... 141
SIGNATURES............................................................ 149
Certification of Executive Officers................................. 151
EXHIBIT INDEX
EXHIBITS
</Table>
2
<PAGE>
DEFINITIONS
As used in this document:
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"Bcf" means billion cubic feet
"MMBtu" means million British thermal units, a measure of heating
value
"Bbl" means barrel
"MBbls" means thousand barrels
"MMBbls" means million barrels
"Boe" means equivalent barrels of oil
"MBoe" means thousand equivalent barrels of oil
"MMBoe" means million equivalent barrels of oil
"Oil" includes crude oil and condensate
"NGLs" means natural gas liquids
"Domestic" means the properties of the Company in the onshore
continental United States and the offshore Gulf of Mexico
"Canada" means the division of the Company encompassing oil and gas
properties located in Canada
"International" means the division of the Company encompassing oil and
gas properties that lie outside the United States and Canada
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included or incorporated by reference in this
report, including, without limitation, statements regarding the Company's future
financial position, business strategy, budgets, projected revenues, projected
costs and plans and objectives of management for future operations, are
forward-looking statements. In addition, forward-looking statements generally
can be identified by the use of forward-looking terminology such as "may,"
"will," "expect," "intend," "project," "estimate," "anticipate," "believe," or
"continue" or the negative thereof or variations thereon or similar terminology.
Although the Company believes that the expectations reflected in such
forward-looking statements are reasonable, it can give no assurance that such
expectations will prove to have been correct. Important factors that could cause
actual results to differ materially from the Company's expectations ("Cautionary
Statements") include, but are not limited to, the Company's assumptions about
energy markets, production levels, reserve levels, operating results,
competitive conditions, technology, the availability of capital resources,
capital expenditure obligations, the supply and demand for oil, natural gas,
NGLs and other products or services, the price of oil, natural gas, NGLs and
other products or services, currency exchange rates, the weather, inflation, the
availability of goods and services, drilling risks, future processing volumes
and pipeline throughput, general economic conditions, either internationally or
nationally or in the jurisdictions in which Devon or its subsidiaries are doing
business, legislative or regulatory changes, including changes in environmental
regulation, environmental risks and liability under federal, state and foreign
environmental laws and regulations, the securities or capital markets and other
factors disclosed under "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations," "Item 2. Properties -- Proved
Reserves and Estimated Future Net Revenue"
3
<PAGE>
"Item 7A. Quantitative and Qualitative Disclosure About Market Risk" and
elsewhere in this report. All subsequent written and oral forward-looking
statements attributable to the Company, or persons acting on its behalf, are
expressly qualified in their entirety by the cautionary statements. The Company
assumes no duty to update or revise its forward-looking statements based on
changes in internal estimates or expectations or otherwise.
4
<PAGE>
PART I
ITEM 1. BUSINESS
GENERAL
Devon Energy Corporation, including its subsidiaries, ("Devon" or the
"Company") is an independent energy company engaged primarily in oil and gas
exploration, development and production, the acquisition of producing
properties, the transportation of oil, gas, and NGLs and the processing of
natural gas. Through its predecessors, Devon began operations in 1971 as a
privately-held company. In 1988, the Company's common stock began trading
publicly on the American Stock Exchange under the symbol "DVN". In addition,
commencing on December 15, 1998, a new class of Devon exchangeable shares began
trading on The Toronto Stock Exchange under the symbol "NSX". These shares are
essentially equivalent to Devon common stock. However, because they are issued
by Devon's wholly-owned subsidiary, Northstar Energy Corporation ("Northstar"),
they qualify as a domestic Canadian investment for Canadian shareholders. They
are exchangeable at any time, on a one-for-one basis, for common shares of
Devon.
The principal and administrative offices of Devon are located at 20 North
Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
Devon operates oil and gas properties in the United States, Canada and
internationally. Devon's North American properties are concentrated within five
geographic areas. Operations in the United States are focused in the Permian
Basin, the Mid-Continent, the Rocky Mountains and onshore and offshore Gulf
Coast. Canadian operations are focused in the Western Canadian Sedimentary Basin
in Alberta and British Columbia. Operations outside North America currently
include Azerbaijan, Brazil, China and West Africa. In addition to its oil and
gas operations, Devon has a large marketing and midstream business. This
includes marketing natural gas, crude oil and NGLs. Marketing and midstream also
includes the construction and operation of pipelines, storage and treating
facilities and gas processing plants. (A detailed description of Devon's
significant properties and associated 2002 developments can be found under "Item
2. Properties beginning on page 13 hereof).
At December 31, 2002, Devon's estimated proved reserves were 1,609 MMBoe,
of which 60% were natural gas reserves and 40% were oil and NGLs reserves. The
present value of pre-tax future net revenues discounted at 10% per annum
assuming essentially constant prices ("10% Present Value") of such reserves was
$15.3 billion. After taxes, the present value was $10.4 billion. Devon is one of
the top five public independent oil and gas companies based in the United
States, as measured by oil and gas reserves.
AVAILABILITY OF REPORTS
Devon makes available free of charge on its internet website, www.dvn.com,
its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports
on Form 8-K and amendments to those reports filed or furnished pursuant to
Section 13(a) or 15(a) of the Securities Exchange Act of 1934 as soon as
reasonably practicable after it electronically files or furnishes them to the
Securities Exchange Commission.
STRATEGY
Devon's primary objectives are to build reserves, production, cash flow and
earnings per share by (a) acquiring oil and gas properties, (b) exploring for
new oil and gas reserves and (c) optimizing production and value from existing
oil and gas properties. Devon's management seeks to achieve these objectives by
(a) concentrating its properties in core areas to achieve economies of scale,
(b) acquiring and developing high profit margin properties, (c) continually
disposing of marginal and non-strategic properties, (d) balancing reserves
between oil and gas, (e) maintaining a high degree of financial flexibility, and
(f) enhancing the value of Devon's production through marketing and midstream
activities.
5
<PAGE>
During 1988, Devon expanded its capital base with its first issuance of
common stock to the public. This transaction began a substantial expansion
program that has continued through the subsequent years. Devon has used a
two-pronged strategy of acquiring producing properties and engaging in drilling
activities to achieve this expansion. Total proved reserves increased from 8
MMBoe at year-end 1987 (without giving effect to the 1998 and 2000 mergers
accounted for as poolings of interests) to 1,609 MMBoe at year-end 2002.
Devon's objective, however, is to increase value per share, not simply to
increase total assets. Proved reserves have grown from 1.31 Boe per share at
year-end 1987 (without giving effect to the 1998 and 2000 poolings) to 10.03 Boe
per share at year-end 2002. This represents a compound annual growth rate of
14.5%. Another measure of value per share is oil and gas production per share.
Production increased from 0.18 Boe per share in 1987 (without giving effect to
the 1998 and 2000 poolings) to 1.17 Boe per share in 2002, a compound annual
growth rate of 13.3%.
DEVELOPMENT OF BUSINESS
On February 24, 2003, Devon and Ocean Energy Inc. ("Ocean") announced their
intention to merge. In the transaction, Devon will issue 0.414 of a share of its
common stock for each outstanding share of Ocean common stock. Also, Devon will
assume approximately $1.8 billion of debt from Ocean. The transaction is subject
to approval by the stockholders of both companies, as well as certain regulatory
approvals. If approved, the transaction is expected to be consummated shortly
after the stockholder meetings.
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. The Mitchell merger added approximately 404 million Boe to Devon's
proved reserves.
Following the Mitchell merger announcement in August 2001, Devon announced
on September 4, 2001, that it had entered into an agreement to acquire Anderson
Exploration Ltd. ("Anderson") for approximately $3.5 billion in cash. This
acquisition closed on October 15, 2001, and therefore had an impact on Devon's
results for the last two and one-half months of 2001. The Anderson acquisition
added approximately 534 million Boe to Devon's proved reserves.
To fund the cash portions of these two acquisitions, as well as to pay
related transaction costs and retire certain long-term debt assumed from
Mitchell and Anderson, Devon entered into long-term debt agreements in October
2001 that totaled $6 billion. Half of this total consisted of $3 billion of
notes and debentures issued on October 3, 2001. Of this total, $1.25 billion
bears interest at 7.875% and matures in September 2031. The remaining $1.75
billion bears interest at 6.875% and matures in September 2011.
The remaining $3 billion of the $6 billion of long-term debt is in the form
of a credit facility that bears interest at floating rates. As of December 31,
2002, $1.9 billion of the original $3 billion balance had been retired. The
primary sources of the repayments were the 2002 issuance of $1 billion of debt
securities, of which $0.8 billion was used to pay down debt, and $1.4 billion
from the sale of certain oil and gas properties, of which $1.1 billion was used
to pay down debt. As of December 31, 2002, the balance outstanding under the
term loan credit facility was $1.1 billion at an average rate of 2.5%. Principal
payments due on this debt are $0.3 billion in April 2006 and $0.8 billion in
October 2006.
During 2002, Devon disposed of approximately $1.4 billion of properties.
Also in 2002, Devon spent $1.5 billion in its exploration and drilling efforts.
See further discussion of Devon's 2002 exploration and drilling efforts in "Item
2. Properties."
FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS
Note 13 to the consolidated financial statements included in Item 8.
Financial Statements and Supplementary Data of this report contains information
on Devon's segments and geographical areas.
6
<PAGE>
DRILLING ACTIVITIES
Devon is engaged in numerous drilling activities on properties presently
owned and intends to drill or develop other properties acquired in the future.
Devon's 2003 drilling activities will be focused in the Rocky Mountains, Permian
Basin, Mid-Continent, Gulf of Mexico and onshore Gulf Coast areas in the U.S.,
the Western Sedimentary basin of Canada and in China and West Africa outside
North America.
The following tables set forth the results of Devon's drilling activity for
the past five years.
UNITED STATES PROPERTIES
<Table>
<Caption>
DEVELOPMENT WELLS EXPLORATORY WELLS
-------------------------------------------------------- ------------------------
GROSS(1) NET(2) GROSS(1)
------------------------ ----------------------------- ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ----- -------- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998................. 374 1 375 153.69 0.10 153.79 24 21 45
1999................. 547 8 555 345.35 3.80 349.15 71 9 80
2000................. 890 13 903 512.18 6.80 518.98 95 11 106
2001................. 961 19 980 638.26 12.91 651.17 148 17 165
2002................. 933 7 940 725.79 4.67 730.46 21 18 39
----- --- ----- -------- ----- -------- --- --- -----
Total................ 3,705 48 3,753 2,375.27 28.28 2,403.55 359 76 435
===== === ===== ======== ===== ======== === === =====
<Caption>
EXPLORATORY WELLS
----------------------------
NET(2)
----------------------------
PRODUCTIVE DRY TOTAL
---------- ------ ------
<S> <C> <C> <C>
1998................. 11.36 7.54 18.90
1999................. 51.91 5.78 57.69
2000................. 80.09 7.41 87.50
2001................. 122.61 11.53 134.14
2002................. 19.60 12.00 31.60
------ ------ ------
Total................ 285.57 44.26 329.83
====== ====== ======
</Table>
CANADIAN PROPERTIES
<Table>
<Caption>
DEVELOPMENT WELLS EXPLORATORY WELLS
-------------------------------------------------------- ------------------------
GROSS(1) NET(2) GROSS(1)
------------------------ ----------------------------- ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ----- -------- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998................. 112 15 127 74.88 11.04 85.92 45 37 82
1999................. 65 9 74 29.61 3.45 33.06 39 23 62
2000................. 130 6 136 68.74 3.25 71.99 70 27 97
2001................. 163 26 189 100.91 16.53 117.44 82 21 103
2002................. 408 20 428 300.93 15.05 315.98 196 37 233
----- --- ----- -------- ----- -------- --- --- -----
Total................ 878 76 954 575.07 49.32 624.39 432... 145 577
===== === ===== ======== ===== ======== === === =====
<Caption>
EXPLORATORY WELLS
----------------------------
NET(2)
----------------------------
PRODUCTIVE DRY TOTAL
---------- ------ ------
<S> <C> <C> <C>
1998................. 32.99 30.50 63.49
1999................. 25.15 16.03 41.18
2000................. 40.60 19.27 59.87
2001................. 63.96 14.05 78.01
2002................. 128.78 27.47 156.25
------ ------ ------
Total................ 291.48 107.32 398.80
====== ====== ======
</Table>
INTERNATIONAL PROPERTIES
<Table>
<Caption>
DEVELOPMENT WELLS EXPLORATORY WELLS
-------------------------------------------------------- ------------------------
GROSS(1) NET(2) GROSS(1)
------------------------ ----------------------------- ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ----- -------- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998................. 59 2 61 18.90 0.60 19.50 9 18 27
1999................. 42 2 44 10.00 0.60 10.60 1 4 5
2000................. 75 1 76 19.71 0.50 20.21 1 9 10
2001................. 84 1 85 21.71 0.51 22.22 6 17 23
2002................. 41 -- 41 8.75 -- 8.75 -- 4 4
----- --- ----- -------- ----- -------- --- --- -----
Total................ 301 6 307 79.07 2.21 81.28 17 52 69
===== === ===== ======== ===== ======== === === =====
<Caption>
EXPLORATORY WELLS
----------------------------
NET(2)
----------------------------
PRODUCTIVE DRY TOTAL
---------- ------ ------
<S> <C> <C> <C>
1998................. 2.90 8.20 11.10
1999................. 0.50 1.60 2.10
2000................. 0.33 6.01 6.34
2001................. 1.96 9.30 11.26
2002................. -- 1.77 1.77
------ ------ ------
Total................ 5.69 26.88 32.57
====== ====== ======
</Table>
TOTAL PROPERTIES
<Table>
<Caption>
DEVELOPMENT WELLS EXPLORATORY WELLS
-------------------------------------------------------- ------------------------
GROSS(1) NET(2) GROSS(1)
------------------------ ----------------------------- ------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ----- -------- ---------- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998................. 545 18 563 247.47 11.74 259.21 78 76 154
1999................. 654 19 673 384.96 7.85 392.81 111 36 147
2000................. 1,095 20 1,115 600.63 10.55 611.18 166 47 213
2001................. 1,208 46 1,254 760.88 29.95 790.83 236 55 291
2002................. 1,382 27 1,409 1,035.47 19.72 1,055.19 217 59 276
----- --- ----- -------- ----- -------- --- --- -----
Total................ 4,884 130 5,014 3,029.41 79.81 3,109.22 808 273 1,081
===== === ===== ======== ===== ======== === === =====
<Caption>
EXPLORATORY WELLS
----------------------------
NET(2)
----------------------------
PRODUCTIVE DRY TOTAL
---------- ------ ------
<S> <C> <C> <C>
1998................. 47.25 46.24 93.49
1999................. 77.56 23.41 100.97
2000................. 121.02 32.69 153.71
2001................. 188.53 34.88 223.41
2002................. 148.38 41.24 189.62
------ ------ ------
Total................ 582.74 178.46 761.20
====== ====== ======
</Table>
7
<PAGE>
- ---------------
(1) Gross wells are the sum of all wells in which Devon owns an interest.
(2) Net wells are the sum of Devon's working interests in gross wells.
As of December 31, 2002, Devon was participating in the drilling of 76
gross (60.71 net) wells in the U.S., 49 gross (28.93 net) wells in Canada and 8
gross (0.89 net) wells internationally. Of these wells, through February 15,
2003, 51 gross (40.91 net) wells in the U.S. and 42 gross (25.07 net) wells in
Canada had been completed as productive. An additional 1 gross (.30 net) well in
the U.S., 1 gross (.50 net) well in Canada and 1 gross (0.50 net) well
internationally were dry holes. The remaining wells were still in process.
CUSTOMERS
Devon sells its gas production to a variety of customers including
pipelines, utilities, gas marketing firms, industrial users and local
distribution companies. Existing gathering systems and interstate and intrastate
pipelines are used to consummate gas sales and deliveries.
The principal customers for Devon's crude oil production are refiners,
remarketers and other companies, some of which have pipeline facilities near the
producing properties. In the event pipeline facilities are not conveniently
available, crude oil is trucked or barged to storage, refining or pipeline
facilities.
No purchaser accounted for over 10% of Devon's revenues in 2002.
OIL AND NATURAL GAS MARKETING
Oil Marketing. Devon's oil production is sold under both long-term (one
year or more) and short-term (less than one year) agreements at prices
negotiated with third parties
Natural Gas Marketing. Devon's gas production is also sold under both
long-term and short-term agreements at prices negotiated with third parties.
Although exact percentages vary daily, as of February 2003 approximately 75% of
Devon's natural gas production was sold under short-term contracts at variable
or market-sensitive prices. These market-sensitive sales are referred to as
"spot market" sales. Another 22% were committed under various long-term
contracts (one year or more) which dedicate the natural gas to a purchaser for
an extended period of time, but still at market sensitive prices. Devon's
remaining gas production was sold under fixed price contracts: 2% under
short-term agreements and 1% under long-term contracts.
Under both long-term and short-term contracts, typically either the entire
contract (in the case of short-term contracts) or the price provisions of the
contract (in the case of long-term contracts) are re-negotiated from daily
intervals up to one-year intervals. The spot market has become progressively
more competitive in recent years. As a result, prices on the spot market have
been volatile.
The spot market is subject to volatility as supply and demand factors in
various regions of North America fluctuate. In addition to fixed price
contracts, Devon periodically enters into hedging arrangements or firm delivery
commitments with a portion of its gas production. These activities are intended
to support targeted gas price levels and to manage the Company's exposure to gas
price fluctuations. (See "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk.")
COMPETITION
The oil and gas business is highly competitive. Devon encounters
competition by major integrated and independent oil and gas companies in
acquiring drilling prospects and properties, contracting for drilling equipment
and securing trained personnel. Intense competition occurs with respect to
marketing, particularly of natural gas. Certain competitors have resources that
substantially exceed those of Devon.
8
<PAGE>
SEASONAL NATURE OF BUSINESS
Generally, but not always, the demand for natural gas decreases during the
summer months and increases during the winter months. Seasonal anomalies such as
mild winters sometimes lessen this fluctuation. In addition, pipelines,
utilities, local distribution companies and industrial users utilize natural gas
storage facilities and purchase some of their anticipated winter requirements
during the summer. This can also lessen seasonal demand fluctuations.
GOVERNMENT REGULATION
Devon's operations are subject to various levels of government controls and
regulations in the United States, Canada and internationally.
UNITED STATES REGULATION
In the United States, legislation affecting the oil and gas industry has
been pervasive and is under constant review for amendment or expansion. Pursuant
to such legislation, numerous federal, state and local departments and agencies
have issued extensive rules and regulations binding on the oil and gas industry
and its individual members, some of which carry substantial penalties for
failure to comply. Such laws and regulations have a significant impact on oil
and gas drilling, gas processing plants and production activities, increase the
cost of doing business and, consequently, affect profitability. Inasmuch as new
legislation affecting the oil and gas industry is commonplace and existing laws
and regulations are frequently amended or reinterpreted, Devon is unable to
predict the future cost or impact of complying with such laws and regulations.
Devon considers the cost of environmental protection a necessary and manageable
part of its business. Devon has been able to plan for and comply with new
environmental initiatives without materially altering its operating strategies.
Exploration and Production. Devon's United States operations are subject
to various types of regulation at the federal, state and local levels. Such
regulation includes requiring permits for the drilling of wells; maintaining
bonding requirements in order to drill or operate wells; implementing spill
prevention plans; submitting notification and receiving permits relating to the
presence, use and release of certain materials incidental to oil and gas
operations; and regulating the location of wells, the method of drilling and
casing wells, the use, transportation, storage and disposal of fluids and
materials used in connection with drilling and production activities, surface
usage and the restoration of properties upon which wells have been drilled, the
plugging and abandoning of wells and the transporting of production. Devon's
operations are also subject to various conservation matters, including the
regulation of the size of drilling and spacing units or proration units, the
number of wells which may be drilled in a unit, and the unitization or pooling
of oil and gas properties. In this regard, some states allow the forced pooling
or integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases, which may make it more difficult to
develop oil and gas properties. In addition, state conservation laws establish
maximum rates of production from oil and gas wells, generally limit the venting
or flaring of gas, and impose certain requirements regarding the ratable
purchase of production. The effect of these regulations is to limit the amounts
of oil and gas Devon can produce from its wells and to limit the number of wells
or the locations at which Devon can drill.
Certain of Devon's oil and gas leases, including its offshore Gulf of
Mexico leases, most of its leases in the San Juan Basin and many of Devon's
leases in southeast New Mexico and Wyoming, are granted by the federal
government and administered by various federal agencies, including the Minerals
Management Service of the Department of the Interior ("MMS"). Such leases
require compliance with detailed federal regulations and orders which regulate,
among other matters, drilling and operations on lands covered by these leases,
and calculation and disbursement of royalty payments to the federal government.
The MMS has been particularly active in recent years in evaluating and, in some
cases, promulgating new rules and regulations regarding competitive lease
bidding and royalty payment obligations for production from federal lands. The
Federal Energy Regulatory Commission ("FERC") also has jurisdiction over certain
offshore activities pursuant to the Outer Continental Shelf Lands Act.
9
<PAGE>
Environmental and Occupational Regulations. Various federal, state and
local laws and regulations concerning the discharge of incidental materials into
the environment, the generation, storage, transportation and disposal of
contaminants or otherwise relating to the protection of public health, natural
resources, wildlife and the environment, affect Devon's exploration,
development, processing, and production operations and the costs attendant
thereto. These laws and regulations increase Devon's overall operating expenses.
Devon maintains levels of insurance customary in the industry to limit its
financial exposure in the event of a substantial environmental claim resulting
from sudden, unanticipated and accidental discharges of oil, salt water or other
substances. However, 100% coverage is not maintained concerning any
environmental claim, and no coverage is maintained with respect to any penalty
or fine required to be paid by Devon because of its violation of any federal,
state or local law. Devon is committed to meeting its responsibilities to
protect the environment wherever it operates and anticipates making increased
expenditures of both a capital and expense nature as a result of the
increasingly stringent laws relating to the protection of the environment.
Devon's unreimbursed expenditures in 2002 concerning such matters were
immaterial, but Devon cannot predict with any reasonable degree of certainty its
future exposure concerning such matters.
Devon is also subject to laws and regulations concerning occupational
safety and health. Due to the continued changes in these laws and regulations,
and the judicial construction of same, Devon is unable to predict with any
reasonable degree of certainty its future costs of complying with these laws and
regulations. Devon considers the cost of safety and health compliance a
necessary and manageable part of its business. Devon has been able to plan for
and comply with new initiatives without materially altering its operating
strategies.
Devon maintains its own internal Environmental, Health and Safety
Department. This department is responsible for instituting and maintaining an
environmental and safety compliance program for Devon. The program includes
field inspections of properties and internal assessments of Devon's compliance
procedures.
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 past mergers 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 December 31, 2002, Devon's consolidated balance sheet included $8 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) Devon's participation in
consent decrees with both other PRPs and the Environmental Protection Agency,
which provide for performing the scope of work required for remediation and
contain covenants not to sue as protection to the PRPs, (ii) participation in
groups as a de minimis PRP, and (iii) the availability of other defenses to
liability. As a result, Devon's monetary exposure is not expected to be
material.
10
<PAGE>
CANADIAN REGULATIONS
The oil and gas industry in Canada is subject to extensive controls and
regulations imposed by various levels of government. It is not expected that any
of these controls or regulations will affect Devon's Canadian operations in a
manner materially different than they would affect other oil and gas companies
of similar size. The following are the most important areas of control and
regulation.
The North American Free Trade Agreement. The North American Free Trade
Agreement ("NAFTA") which became effective on January 1, 1994 carries forward
most of the material energy terms contained in the Canada-U.S. Free Trade
Agreement. In the context of energy resources, Canada continues to remain free
to determine whether exports to the United States or Mexico will be allowed,
provided that any export restrictions do not (i) reduce the proportion of energy
exported relative to the supply of the energy resource; (ii) impose an export
price higher than the domestic price; or (iii) disrupt normal channels of
supply. All parties to NAFTA are also prohibited from imposing minimum export or
import price requirements.
Royalties and Incentives. Each province and the federal government of
Canada have legislation and regulations governing land tenure, royalties,
production rates and taxes, environmental protection and other matters under
their respective jurisdictions. The royalty regime is a significant factor in
the profitability of oil and natural gas production. Royalties payable on
production from lands other than Crown lands are determined by negotiations
between the parties. Crown royalties are determined by government regulation and
are generally calculated as a percentage of the value of the gross production
with the royalty rate dependent in part upon prescribed reference prices, well
productivity, geographical location, field discovery date and the type and
quality of the petroleum product produced. From time to time, the governments of
Canada, Alberta and British Columbia have also established incentive programs
such as royalty rate reductions, royalty holidays and tax credits for the
purpose of encouraging oil and natural gas exploration or enhanced recovery
projects. These incentives generally have the effect of increasing the cash flow
to the producer.
Pricing and Marketing. The price of oil and natural gas sold is determined
by negotiation between buyers and sellers. An order from the National Energy
Board ("NEB") is required for oil exports from Canada. Any oil export to be made
pursuant to an export contract of longer than one year, in the case of light
crude, and two years, in the case of heavy crude, duration (up to 25 years)
requires an exporter to obtain an export license from the NEB. The issue of such
a license requires the approval of the Government of Canada. Natural gas
exported from Canada is also subject to similar regulation by the NEB. Exporters
are free to negotiate prices and other terms with purchasers, provided that the
export contracts in excess of two years must continue to meet certain criteria
prescribed by the NEB. The governments of Alberta and British Columbia also
regulate the volume of natural gas which may be removed from those provinces for
consumption elsewhere based on such factors as reserve availability,
transportation arrangements and market considerations.
Environmental Regulation. The oil and natural gas industry is subject to
environmental regulation pursuant to local, provincial and federal legislation.
Environmental legislation provides for restrictions and prohibitions on releases
or emissions of various substances produced or utilized in association with
certain oil and gas industry operations. In addition, legislation requires that
well and facility sites be abandoned and reclaimed to the satisfaction of
provincial authorities. A breach of such legislation may result in the
imposition of fines and penalties. Devon is committed to meeting its
responsibilities to protect the environment wherever it operates and anticipates
making increased expenditures of both a capital and expense nature as a result
of the increasingly stringent laws relating to the protection of the
environment. Devon's unreimbursed expenditures in 2002 concerning such matters
were immaterial, but Devon cannot predict with any reasonable degree of
certainty its future exposure concerning such matters.
Kyoto Protocol. In December 2002 the Government of Canada ratified the
Kyoto Protocol. This protocol calls for Canada to reduce its greenhouse gas
emissions to 6 percent below 1990 levels during the period between 2008 and
2012. The protocol will only become legally binding when it is ratified by at
least 55 countries, covering at least 55 percent of the emissions addressed by
the protocol. If the protocol
11
<PAGE>
becomes legally binding, it is expected to affect the operation of all
industries in Canada, including the oil and gas industry. As details of the
implementation of this protocol have yet to be announced, the effect on Devon
cannot be determined at this time.
Investment Canada Act. The Investment Canada Act requires Government of
Canada approval, in certain cases, of the acquisition of control of a Canadian
business by an entity that is not controlled by Canadians. In certain
circumstances, the acquisition of natural resource properties may be considered
to be a transaction requiring such approval.
INTERNATIONAL REGULATIONS
The oil and gas industry is subject to various types of regulation
throughout the world. Legislation affecting the oil and gas industry has been
pervasive and is under constant review for amendment or expansion. Pursuant to
such legislation, government agencies have issued extensive rules and
regulations binding on the oil and gas industry and its individual members, some
of which carry substantial penalties for failure to comply. Such laws and
regulations have a significant impact on oil and gas drilling and production
activities, increase the cost of doing business and, consequently, affect
profitability. Inasmuch as new legislation affecting the oil and gas industry is
commonplace and existing laws and regulations are frequently amended or
reinterpreted, Devon is unable to predict the future cost or impact of complying
with such laws and regulations. The following are significant areas of
regulation.
Exploration and Production. Devon's oil and gas concessions and permits
are granted by host governments and administered by various foreign government
agencies. Such foreign governments require compliance with detailed regulations
and orders which regulate, among other matters, drilling and operations on areas
covered by concessions and permits and calculation and disbursement of royalty
payments, taxes and minimum investments to the government.
Regulation includes requiring permits for the drilling of wells;
maintaining bonding requirements in order to drill or operate wells;
implementing spill prevention plans; submitting notification and receiving
permits relating to the presence, use and release of certain materials
incidental to oil and gas operations; and regulating the location of wells, the
method of drilling and casing wells, the use, transportation, storage and
disposal of fluids and materials used in connection with drilling and production
activities, surface usage and the restoration of properties upon which wells
have been drilled, the plugging and abandoning of wells and the transporting of
production. Devon's operations are also subject to regulations which may limit
the number of wells or the locations at which Devon can drill.
Production Sharing Contracts. Many of Devon's international licenses are
governed by Production Sharing Contracts (PSC) between the concessionaires and
the granting government agency. PSCs are contracts that define and regulate the
framework for investments, revenue sharing, and taxation of mineral interests in
foreign countries. Unlike most domestic leases, PSCs have defined production
terms and time limits of generally 30 years. Many PSCs allow for recovery of
investments including carried government percentages. PSCs generally contain
sliding scale revenue sharing provisions. For example, at either higher
production rates or higher cumulative rates of return, PSCs allow governments to
generally retain higher fractions of revenue.
Environmental Regulations. Various government laws and regulations
concerning the discharge of incidental materials into the environment, the
generation, storage, transportation and disposal of contaminants or otherwise
relating to the protection of public health, natural resources, wildlife and the
environment, affect Devon's exploration, development, processing and production
operations and the costs attendant thereto. In general, this consists of
preparing Environmental Impact Assessments in order to receive required
environmental permits to conduct drilling or construction activities. Such
regulations also typically include requirements to develop emergency response
plans, waste management plans, and spill contingency plans. In some countries,
the application of worldwide standards, such as ISO 14000 governing
Environmental Management Systems, are required to be implemented for
international oil and gas operations.
12
<PAGE>
EMPLOYEES
As of December 31, 2002, Devon's staff consisted of 3,436 full-time
employees. Devon believes that it has good labor relations with its employees.
ITEM 2. PROPERTIES
Substantially all of Devon's properties consist of interests in developed
and undeveloped oil and gas leases and mineral acreage located in Devon's core
operating areas and mid-stream assets. These interests entitle Devon to drill
for and produce oil, natural gas and NGLs from specific areas. Devon's interests
are mostly in the form of working interests and, to a lesser extent, overriding
royalty, volumetric production payments, foreign government concessions, mineral
and net profits interests and other forms of direct and indirect ownership in
oil and gas properties.
Devon's most significant midstream asset is its 3,100 mile Bridgeport
pipeline system and 650 MMcfd Bridgeport gas processing plant located in North
Texas.
PROVED RESERVES AND ESTIMATED FUTURE NET REVENUE
Set forth below is a summary of the reserves which were evaluated by
independent petroleum consultants for each of the years ended 2002, 2001 and
2000.
<Table>
<Caption>
2002 2001 2000
------------------- ------------------- -------------------
ESTIMATED AUDITED ESTIMATED AUDITED ESTIMATED AUDITED
--------- ------- --------- ------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
Domestic...................... 12% 61% 67% 9% 80% 17%
Canada........................ 31% --% 43% --% 100% --%
International................. 100% --% 100% --% 100% --%
</Table>
Estimated reserves are those quantities of reserves which were estimated by
an independent petroleum consultant. Audited reserves are those quantities of
reserves which were estimated by Devon employees and audited by an independent
petroleum consultant.
The domestic reserves were evaluated by the independent petroleum
consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company
Petroleum Consultants in each of the years presented. The Canadian reserves were
estimated by the independent petroleum consultants of AJM Petroleum Consultants
in 2002; Paddock Lindstrom & Associates and Gilbert Laustsen Jung Associates,
Ltd. in 2001; and Paddock Lindstrom & Associates in 2000. The International
reserves were estimated by the independent petroleum consultants of Ryder Scott
Company Petroleum Consultants in each of the years presented.
The following table sets forth Devon's estimated proved reserves, the
estimated future net revenues therefrom and the 10% Present Value thereof as of
December 31, 2002. These estimates correspond with the method used in presenting
the "Supplemental Information on Oil and Gas Operations" in Note 14 to
13
<PAGE>
Devon's Consolidated Financial Statements included herein, except that federal
income taxes attributable to such future net revenues have been disregarded in
the presentation below.
<Table>
<Caption>
TOTAL PROVED PROVED
PROVED DEVELOPED UNDEVELOPED
RESERVES RESERVES RESERVES
-------- --------- -----------
<S> <C> <C> <C>
TOTAL RESERVES
Oil (MMBbls)........................................ 444 260 184
Gas (Bcf)........................................... 5,836 4,618 1,218
NGL (MMBbls)........................................ 192 150 42
MMBoe(1)............................................ 1,609 1,180 429
Pre-tax Future Net Revenue ($ millions)(2).......... 27,270 19,297 7,973
Pre-tax 10% Present Value ($ millions)(2)........... 15,307 11,571 3,736
Standardized measure of discounted future net cash
flows ($ millions)(3)............................ 10,365
U.S. RESERVES
Oil (MMBbls)........................................ 147 135 12
Gas (Bcf)........................................... 3,552 2,802 750
NGL (MMBbls)........................................ 146 117 29
MMBoe(1)............................................ 885 719 166
Pre-tax Future Net Revenue ($ millions)(2).......... 13,578 11,281 2,297
Pre-tax 10% Present Value ($ millions)(2)........... 7,740 6,594 1,146
Standardized measure of discounted future net cash
flows ($ millions)(3)............................ 5,510
CANADIAN RESERVES
Oil (MMBbls)........................................ 149 119 30
Gas (Bcf)........................................... 2,284 1,816 468
NGL (MMBbls)........................................ 46 33 13
MMBoe(1)............................................ 576 455 121
Pre-tax Future Net Revenue ($ millions)(2).......... 10,566 7,871 2,695
Pre-tax 10% Present Value ($ millions)(2)........... 6,258 4,878 1,380
Standardized measure of discounted future net cash
flows ($ millions)(3)............................ 3,890
INTERNATIONAL RESERVES
Oil (MMBbls)........................................ 148 6 142
Gas (Bcf)........................................... -- -- --
NGL (MMBbls)........................................ -- -- --
MMBoe(1)............................................ 148 6 142
Pre-tax Future Net Revenue ($ millions)(2).......... 3,126 145 2,981
Pre-tax 10% Present Value ($ millions)(2)........... 1,309 99 1,210
Standardized measure of discounted future net cash
flows ($ millions)(3)............................ 965
</Table>
- ---------------
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil,
based upon the approximate relative energy content of natural gas to oil,
which rate is not necessarily indicative of the relationship of gas to oil
prices. NGL reserves are converted to Boe on a one-to-one basis with oil.
The respective prices of gas and oil are affected by market conditions and
other factors in addition to relative energy content.
14
<PAGE>
(2) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and development costs. The amounts shown do not give effect to
non-property related expenses such as general and administrative expenses
not related directly to oil and gas producing, debt service and future
income tax expense or to depreciation, depletion and amortization.
These amounts were calculated using prices and costs in effect as of
December 31, 2002. These prices were not changed except where different
prices were fixed and determinable from applicable contracts. These
assumptions yield average prices over the life of Devon's properties of
$27.99 per Bbl of oil, $3.88 per Mcf of natural gas and $17.07 per Bbl of
NGLs. These prices compare to December 31, 2002, New York Mercantile
Exchange prices of $31.20 per Bbl for crude oil and of $4.74 per MMBtu for
natural gas.
(3) See Note 14 to the consolidated financial statements included in Item 8 of
this report.
No estimates of Devon's proved reserves have been filed with or included in
reports to any federal or foreign governmental authority or agency since the
beginning of the last fiscal year except (i) in filings with the SEC and
Canadian Securities Regulators and (ii) in filings with the Department of Energy
("DOE"). Reserve estimates filed by Devon with the SEC and Canadian Securities
Regulators correspond with the estimates of Devon reserves contained herein.
Reserve estimates filed with the DOE are based upon the same underlying
technical and economic assumptions as the estimates of Devon's reserves included
herein. However, the DOE requires reports to include the interests of all owners
in wells that Devon operates and to exclude all interests in wells that Devon
does not operate.
The prices used in calculating the estimated future net revenues
attributable to proved reserves do not necessarily reflect market prices for
oil, gas and NGL production subsequent to December 31, 2002. There can be no
assurance that all of the proved reserves will be produced and sold within the
periods indicated, that the assumed prices will be realized or that existing
contracts will be honored or judicially enforced.
The process of estimating oil, gas and NGLs reserves is complex, requiring
significant subjective decisions in the evaluation of available geological,
engineering and economic data for each reservoir. The data for a given reservoir
may change substantially over time as a result of, among other things,
additional development activity, production history and viability of production
under varying economic conditions. Consequently, material revisions to existing
reserve estimates may occur in the future.
PRODUCTION, REVENUE AND PRICE HISTORY
Certain information concerning oil and natural gas production, prices,
revenues (net of all royalties, overriding royalties and other third party
interests) and operating expenses for the three years ended December 31, 2002,
is set forth in "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations."
WELL STATISTICS
The following table sets forth Devon's producing wells as of December 31,
2002:
<Table>
<Caption>
OIL WELLS GAS WELLS TOTAL WELLS
----------------- ----------------- -----------------
GROSS(1) NET(2) GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------ -------- ------
<S> <C> <C> <C> <C> <C> <C>
U.S. ............................ 6,869 2,777 9,632 6,892 16,501 9,669
Canada........................... 2,808 1,695 4,066 2,307 6,874 4,002
International.................... 20 3 -- -- 20 3
----- ----- ------ ----- ------ ------
Total............................ 9,697 4,475 13,698 9,199 23,395 13,674
===== ===== ====== ===== ====== ======
</Table>
- ---------------
(1) Gross wells are the total number of wells in which Devon owns a working
interest.
(2) Net refers to gross wells multiplied by Devon's fractional working interests
therein.
15
<PAGE>
Devon also held numerous overriding royalty interests in oil and gas wells,
a portion of which are convertible to working interests after recovery of
certain costs by third parties. After converting to working interests, these
overriding royalty interests will be included in Devon's gross and net well
count.
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth Devon's developed and undeveloped oil and
gas lease and mineral acreage as of December 31, 2002.
<Table>
<Caption>
DEVELOPED UNDEVELOPED
----------------- -----------------
GROSS(1) NET(2) GROSS(1) NET(2)
-------- ------ -------- ------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
United States
Permian Basin................................... 565 297 1,029 462
Mid-Continent................................... 1,070 783 1,809 1,179
Rocky Mountains................................. 495 287 1,156 601
Gulf Coast
Offshore..................................... 495 286 781 467
Onshore...................................... 524 243 218 91
----- ----- ------ ------
Total Gulf Coast............................. 1,019 529 999 558
----- ----- ------ ------
Total U. S........................................ 3,149 1,896 4,993 2,800
Canada............................................ 3,655 2,296 16,370 11,468
International..................................... 54 6 11,759 7,437
----- ----- ------ ------
Grand Total....................................... 6,858 4,198 33,122 21,705
===== ===== ====== ======
</Table>
- ---------------
(1) Gross acres are the total number of acres in which Devon owns a working
interest.
(2) Net refers to gross acres multiplied by Devon's fractional working interests
therein.
OPERATION OF PROPERTIES
The day-to-day operations of oil and gas properties are the responsibility
of an operator designated under pooling or operating agreements. The operator
supervises production, maintains production records, employs field personnel and
performs other functions. The charges under operating agreements customarily
vary with the depth and location of the well being operated.
Devon is the operator of 14,001 of its wells. As operator, Devon receives
reimbursement for direct expenses incurred in the performance of its duties as
well as monthly per-well producing and drilling overhead reimbursement at rates
customarily charged in the area to or by unaffiliated third parties. In
presenting its financial data, Devon records the monthly overhead reimbursements
as a reduction of general and administrative expense, which is a common industry
practice.
ORGANIZATION STRUCTURE
Devon's North American properties are concentrated within five geographic
areas. Operations in the United States are focused in the Permian Basin, the
Mid-Continent, the Rocky Mountains and onshore and offshore Gulf Coast regions.
Canadian operations are focused in the Western Canadian Sedimentary Basin in
Alberta and British Columbia. Operations outside North America currently include
Azerbaijan, Brazil, China and West Africa. Maintaining a tight geographic focus
in selected core areas has allowed Devon to improve operating and capital
efficiency.
16
<PAGE>
UNITED STATES PROPERTIES
The Permian Basin
The Permian Basin includes portions of Southeast New Mexico and West Texas.
These assets include conventional oil and gas properties from a wide variety of
geologic formations and productive depths. The Permian Basin represented 9% of
Devon's proved reserves at December 31, 2002.
Devon's leasehold position in Southeast New Mexico encompasses more than
102,000 acres of developed lands and 237,000 acres of undeveloped land and
minerals. Historically, Devon has been a very active operator in this area
developing gas from the high productivity Morrow formation and oil in the lower
risk Delaware formation.
In the West Texas area of the Permian Basin, Devon maintains a base of oil
production with long-life reserves. Many of these reserves are from both
operated and non-operated positions in large enhanced oil recovery units such as
the Wasson ODC Unit, the Willard Unit, the Reeves Unit, the North Welch Unit and
the Anton Irish (Clearfork) Unit. These oil-producing units often exhibit long
lives with low decline rates. Devon also owns a significant acreage position in
West Texas with over 194,000 acres of developed lands and over 224,000 acres of
undeveloped land and minerals at December 31, 2002.
Mid-Continent
The Mid-Continent region includes portions of Texas, Oklahoma, Kansas,
Mississippi and Louisiana. These areas encompass a wide variety of geologic
formations and productive depths and produce both oil and natural gas. Devon's
Mid-Continent production has historically come from conventional oil and gas
properties, but Devon has recently established two non-conventional gas
operations in the Mid-Continent region: the Barnett Shale and the Cherokee
coalbed methane project. The Mid-Continent region represented 30% of Devon's
proved reserves at December 31, 2002.
The most significant asset acquired by Devon in its 2002 acquisition of
Mitchell was a substantial interest in the Barnett Shale of North Texas. The
Barnett Shale is known as a tight gas formation. This means that, in its natural
state, the formation is resistant to the production of natural gas. Mitchell
spent decades understanding how to efficiently develop and produce this gas. The
resulting technology yielded a low-risk and highly profitable natural gas
operation. Devon holds 525,000 net acres and over 1,100 producing wells in the
Barnett Shale. Devon's average working interest is approximately 95%. The
Barnett Shale is a unique, unconventional natural gas resource that offers
immediate low-risk production growth and the potential for additional drilling
locations.
Devon has experienced success extracting gas from the Barnett Shale by
using light sand fracturing. Light sand fracturing yields better results than
earlier techniques and is less expensive and can be used to complete new wells
and to refracture existing wells. Refractured wells often exceed their original
flow rates. Devon is also investigating horizontal drilling and closer well
spacing to further enhance the value of the Barnett Shale.
Devon's marketing and midstream business transports, treats and processes
its Barnett Shale production along with Barnett Shale production from unrelated
third parties. The transport system consists of approximately 3,100 miles of
pipeline, a 650 MMcf per day gas processing plant, and a 15,000 Bbls per day NGL
fractionator.
In 2003, Devon plans to drill up to 450 new Barnett Shale wells and
refracture 64 wells. Devon is also conducting exploratory pilot projects outside
the core development area in an effort to expand the productive area. The
Barnett Shale is expected to continue to be an important growth area for Devon
for the foreseeable future. Current production from the Barnett Shale is
approximately 345 MMcf and 21,700 Bbls of oil and NGLs per day net.
The other non-conventional asset Devon is developing in the Mid-Continent
region is the Cherokee coalbed methane project. Coalbed methane is natural gas
produced from underground coal deposits. Devon
17
<PAGE>
acquired over 400,000 net acres within the Cherokee area of Southeast Kansas and
Northeast Oklahoma in 2001.
Devon's East Texas properties are a significant conventional asset. A large
portion of this asset base was initially acquired in 1999. The Carthage and
Bethany fields are two of the primary properties. These properties produce from
the Cotton Valley sands, the Travis Peak sands and from shallower sands and
carbonates. Devon operates over 500 producing wells in this area and utilizes a
one to two rig drilling program to continue the low-risk, infill development of
this area.
The 2002 acquisition of Mitchell added a complementary asset base to the
East Texas area. These properties are located on the western side of the East
Texas Basin and produce from the Bossier, Cotton Valley and Travis Peaks sands.
Devon operates approximately 400 producing wells in this area and plans to
continue the development drilling program with one to two rigs. Devon's current
net production in East Texas is approximately 123 MMcf and 3,800 Bbls of oil and
NGLs per day.
Rocky Mountain Region
Devon's operations in the Rocky Mountain region include properties in
Wyoming, Utah, and Northern New Mexico. These assets include conventional oil
and gas properties and coalbed methane projects. As of December 31, 2002, the
Rocky Mountain region comprised 11% of Devon's proved reserves.
Devon began producing coalbed methane in the San Juan Basin of New Mexico
in the mid-1980s and began drilling coalbed methane wells in the Powder River
Basin of Wyoming in 1998. As of December 31, 2002, Devon has drilled over 1,500
coalbed methane wells in the Powder River Basin. Devon's net coalbed methane gas
production from the basin was approximately 80 MMcf per day as of December 31,
2002, and Devon plans to drill more than 100 wells in the Powder River Basin in
2003. Current production in the basin is primarily from the Wyodak coal
formation.
The deeper Big George formation is currently being tested by Devon and
others with working interests in the area. Increased development in the Big
George is subject to an Environmental Impact Statement, which has been completed
and is expected to be approved within the next few months. Pending this approval
and the success of current pilot projects, the Big George could significantly
expand the coalbed methane play into the western portion of the Powder River
Basin. Devon's leasehold in this area would allow for the development of four
projects in the Big George.
Devon is also continuing to develop conventional gas operations at the
Washakie field in Wyoming. Devon drilled 31 wells in 2002 and plans to drill
another 30 wells in 2003. Devon has interests in over 200,000 acres. Devon's
current net production from Washakie is approximately 77 MMcf and 1,100 Bbls of
oil and NGLs per day.
GULF OF MEXICO AND GULF COAST
Devon is active in the offshore Gulf of Mexico and onshore South Texas and
South Louisiana. Devon operates 100 structures in the Gulf of Mexico
predominantly in the outer shelf area offshore Louisiana. The Gulf of Mexico and
Gulf Coast region represented 5% of Devon's proved reserves at December 31,
2002.
Devon is applying four-component, or 4-C, seismic technology to identify
prospects on large tracts of its shelf acreage. Traditional seismic techniques
have not been successful in imaging reservoirs lying below shallow gas
reservoirs and salt deposits, but 4-C seismic technology is allowing Devon's
geoscientists to more accurately picture these unexplored formations. Devon has
conducted two large 4-C seismic surveys offshore Louisiana and, in 2002, Devon
drilled four successful wells in the West Cameron area based on 4-C data. Devon
is also reprocessing large seismic data volumes using pre-stack depth migration
to prospect for oil and gas in the outer shelf. In addition, Devon is utilizing
new long cable 3-D seismic data to better image deep shelf prospects. Devon has
developed a significant inventory of drilling opportunities for deeper gas near
our infrastructure in offshore Louisiana and offshore Texas.
18
<PAGE>
In the deepwater Gulf of Mexico, Devon participated in its first subsalt
discovery in 1999 in the Enchilada Field located in Garden Banks 128. Since then
Devon has operated several successful subsea completions ranging from Garden
Banks to Viosca Knoll. Devon has experience with the successful installation and
operation of subsea production equipment, which is an important component of any
deepwater program. Devon's Pecten discovery in Viosca Knoll Block 694, a subsea
tieback completed in 2001, is currently producing approximately 17 MMcf of gas
per day.
Because deepwater exploration requires significant capital expenditures,
Devon's strategy is to share projects with experienced partners to mitigate
risk. In 2002, Devon entered into a four-well joint venture with ChevronTexaco
that will earn Devon a 25% working interest in 71 deepwater blocks and 14
identified exploratory prospects. Devon also made a potentially significant
discovery in 2002 in 8,200 feet of water at Cascade located in Walker Ridge
Block 206 and plans to participate with other partners in four or five deepwater
wells in 2003, including a confirmation well at Cascade.
Devon's operations in the Gulf Coast region include operations onshore in
South Texas, where exploration for oil and gas is accelerating. Devon's
activities in this area have focused on exploration in the Edwards, Wilcox and
Frio/Vicksburg formations. Devon also acquired additional production and
undeveloped acreage in the South Texas area from its acquisition of Mitchell.
CANADA
Devon's acquisition of Anderson in late 2001 significantly increased the
relative importance of Devon's Canadian operations. The Anderson acquisition
strengthened Devon's holdings in the Deep Basin located in Western Alberta and
Eastern British Columbia, and the Foothills Region of Northeastern British
Columbia. As of December 31, 2002, 36% of Devon's proved reserves were in
Canada.
Devon had sought for years to obtain a significant acreage position in the
Deep Basin, but other operators, including Anderson, already controlled most of
the acreage. As a result of the Anderson acquisition, Devon now holds over
800,000 net acres in the Deep Basin. The profitability of Devon's operations in
the Deep Basin is enhanced by its ownership in nine gas processing plants in the
area. Devon plans to drill about 100 wells in the Deep Basin in 2003. These
reservoirs tend to be rich in liquids, producing up to 100 barrels of NGLs with
each MMcf of gas.
Late in 2002, Devon commenced production from the first of several wells it
has drilled in the Grizzly Valley area of the Foothills Region of Northeastern
British Columbia. Due to gas pipeline and processing limitations, initial
production has been limited to 10 MMcf of gas per day. However, a pipeline
extension slated for completion in the second quarter of 2003 should allow
production to increase to about 35 MMcf per day.
Devon acquired from Anderson approximately 1.5 million net acres in the
MacKenzie Delta region and the shallow waters of the Beaufort Sea in Northern
Canada. In 2002, a Devon well in the MacKenzie Delta encountered over 110 feet
of natural gas pay in the Kamik sand. Two to three more exploratory wells are
planned by Devon in the MacKenzie Delta in 2003.
Devon has been active for over a decade in Northeastern British Columbia,
an area in which Devon owns approximately 1.35 million net undeveloped acres of
land. In 2002, Devon participated in the drilling of 67 gross wells and plans to
participate in the drilling of approximately 93 wells in 2003.
The Peace River Arch area is a more mature area with both light oil and
natural gas potential. Most of Devon's position in the Peace River Arch was
acquired through the Anderson acquisition. Devon holds roughly 730,000 net
undeveloped acres in the Peace River Arch, and the average production in 2002
was approximately 140 MMcf of natural gas and 7,500 Bbls of NGLs per day net. In
2003, Devon plans to participate in the drilling of 71 gross wells in the Peace
River Arch. Devon has an interest in a production and processing infrastructure
in the Peace River Arch, which enhances Devon's operations in the area.
19
<PAGE>
In the Northern Plains region of Northeastern Alberta, Devon has been
active for many years. While the area is a highly developed area with
winter-only access, Devon is very active, drilling in excess of 100 gross wells
per year. In 2002, average daily net production from the area was about 150 MMcf
of natural gas and approximately 3,400 Bbls of NGLs net. Natural gas is
encountered in multiple horizons at depths generally less than 1,300 feet. Devon
holds approximately 2 million net undeveloped acres in this area.
Devon has about 400,000 net undeveloped acres in the central and southern
region of Alberta and the average production from this area in 2002 was
approximately 80 MMcf of natural gas and 20,000 Bbls of NGLs per day net.
Planned activity in 2003 includes drilling approximately 70 gross wells that
vary from deep Devonian tests to shallow Cretaceous tests.
Devon is also active in exploration for and production of "cold-flow" heavy
oil in the Lloydminster area of Alberta and Saskatchewan where oil is found in
multiple horizons generally at depths of 1,000 to 2,000 feet. In 2003, Devon
plans to drill 134 gross wells with primarily a development focus. Average daily
production from the area in 2002 was approximately 37 MMcf of natural gas and
13,750 Bbls of crude oil net.
Devon is also active in the evaluation of thermal heavy oil in Alberta
through its 13% ownership interest in the Surmont project, operated by
ConocoPhillips, and is actively evaluating the development of a 100% working
interest heavy oil lease at Jackfish and an 83% working interest heavy oil
project at Dover. Each of these heavy oil projects target bitumen (heavy
tar-like oil) through the use of Steam Assisted Gravity Drainage whereby a pair
of horizontal wells are utilized. Steam is injected in one well and is used to
heat the bitumen to allow it to gravity drain to the other horizontal production
well.
INTERNATIONAL
Devon's international activities are currently focused in development
projects in Azerbaijan and China and deepwater exploration in the combined South
Atlantic Margin of Brazil and West Africa. In 2002, Devon divested all remaining
interests in Argentina, Indonesia and Egypt. As of December 31, 2002, 9% of
Devon's proved reserves were in countries outside North America.
In Azerbaijan, Devon has a 5.6% carried working interest in the large
Azeri-Chirag-Gunashli, or ACG, oil development project. Devon estimates that the
ACG field contains over 4.6 billion barrels of gross proved oil reserves. The
development project commenced in 2002. The Baku-T'Bilisi-Ceyhan (BTC) pipeline
to export oil for this project has been approved by the governments of
Azerbaijan, Georgia and Turkey.
In China, Devon is an acreage holder in the Pearl River Mouth Basin in the
South China Sea and has been successful in discovering two new fields. Devon is
currently developing the Devon operated Panyu development project and expects
oil production from two offshore platforms and into a floating production-
storage and offloading vessel to commence in late 2003. Gross capital
expenditures for the project are $340 million, with Devon owning a 24.5% working
interest. Peak production is expected to reach 58,000 Bbls of oil per day
(15,000 Bbls of oil per day net to Devon) in 2004.
Devon's international exploration efforts are strategically focused in the
combined South Atlantic deep water region of West Africa and Brazil. Devon's
presence in West Africa began in 1992 with exploration efforts resulting in the
discoveries of the Tchatamba fields in the shallow waters offshore Gabon. In
this region, Devon has five blocks and holds over 3.2 million net acres. Devon
plans to drill deepwater exploratory wells in its West Africa portfolio in Ghana
and Gabon in 2003. In Brazil, Devon will be acquiring a 3-D survey in a
Devon-operated deepwater block in early 2003 in order to identify future
drilling opportunities.
20
<PAGE>
SIGNIFICANT PROPERTIES
The following table sets forth proved reserve information on the most
significant geographic areas in which Devon's properties are located as of
December 31, 2002.
<Table>
<Caption>
STANDARDIZED
MEASURE OF
DISCOUNTED
10% PRESENT FUTURE NET
Oil Gas NGLs MMBoe VALUE 10% PRESENT CASH FLOWS
(MMBbls) (Bcfcf) (MMBbls) MMBoe(1) %(2) (IN MILLIONS)(3) VALUE %(4) (IN MILLIONS)(5)
-------- ------- -------- -------- ----- ---------------- ----------- ----------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
UNITED STATES
Permian Basin........ 90 283 13 150 9.3% $ 1,418 9.3%
Mid-Continent........ 9 2,103 116 475 29.5% 3,918 25.6%
Rocky Mountain....... 22 835 9 170 10.6% 1,100 7.2%
Gulf
Offshore........... 23 194 4 60 3.7% 922 6.0%
Onshore............ 3 137 4 30 1.9% 382 2.5%
--- ----- --- ----- ----- ------- -----
Total............ 26 331 8 90 5.6% 1,304 8.5%
--- ----- --- ----- ----- ------- -----
TOTAL U.S. ............ 147 3,552 146 885 55.0% 7,740 50.6% $ 5,510
CANADA
Total(6)........... 149 2,284 46 576 35.8% 6,258 40.9% 3,890
INTERNATIONAL
Total.............. 148 -- -- 148 9.2% 1,309 8.5% 965
--- ----- --- ----- ----- ------- ----- -------
Grand Total............ 444 5,836 192 1,609 100.0% $15,307 100.0% $10,365
=== ===== === ===== ===== ======= ===== =======
</Table>
- ---------------
(1) Gas reserves are converted to Boe at the rate of six Mcf of gas per Bbl of
oil, based upon the approximate relative energy content of natural gas to
oil, which rate is not necessarily indicative of the relationship of gas to
oil prices. NGL reserves are converted to Boe on a one-to-one basis with
oil. The respective prices of gas and oil are affected by market and other
factors in addition to relative energy content.
(2) Percentage which MMBoe for the basin or region bears to total MMBoe for all
proved reserves.
(3) Determined in accordance with SEC guidelines, except that no effect is given
to future income taxes.
(4) Percentages which present value for the basin or region bears to total
present value for all proved reserves.
(5) Determined in accordance with SEC guidelines.
(6) Canadian dollars converted to U.S. dollars at the rate of $1 Canadian:
$0.6331 U.S.
TITLE TO PROPERTIES
Title to properties is subject to contractual arrangements customary in the
oil and gas industry, liens for current taxes not yet due and, in some
instances, other encumbrances. Devon believes that such burdens do not
materially detract from the value of such properties or from the respective
interests therein or materially interfere with their use in the operation of the
business.
As is customary in the industry in the case of undeveloped properties,
little investigation of record title is made at the time of acquisition (other
than a preliminary review of local records). Investigations, generally including
a title opinion of outside counsel, are made prior to the consummation of an
acquisition of producing properties and before commencement of drilling
operations on undeveloped properties.
21
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
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 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.
Devon is a defendant in certain private royalty owner litigation filed in
Wyoming regarding deductibility of certain post production costs from royalties
payable by Devon. The plaintiffs in these lawsuits propose to expand them into
county or state-wide class actions relating specifically to transportation and
related costs associated with Devon's Wyoming gas production. A significant
portion of such production is, or will be, transported through facilities owned
by Thunder Creek Gas Services, L.L.C., of which Devon owns a 75% interest. Devon
believes that it has acted reasonably and paid royalties in good faith and in
accordance with its obligations under its oil and gas leases and applicable law,
and Devon does not believe that it is subject to material exposure in
association with this litigation.
OTHER MATTERS
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of 2002.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET PRICE
Devon's common stock has been traded on the American Stock Exchange (the
"AMEX") since September 29, 1988. Prior to September 29, 1988, Devon's common
stock was privately held. Commencing on December 15, 1998, a new class of Devon
exchangeable shares began trading on The Toronto Stock Exchange ("TSE") under
the symbol "NSX". These shares are essentially equivalent to Devon common stock.
However, because they are issued by Devon's wholly-owned subsidiary, Northstar,
22
<PAGE>
they qualify as a domestic Canadian investment for Canadian shareholders. They
are exchangeable at any time, on a one-for-one basis, for common shares of Devon
at the holder's option.
The following table sets forth the high and low sales prices for Devon
common stock and exchangeable shares as reported by the AMEX and TSE for the
periods indicated.
<Table>
<Caption>
AMERICAN STOCK EXCHANGE THE TORONTO STOCK EXCHANGE
----------------------------- ------------------------------
HIGH LOW AVERAGE DAILY HIGH LOW AVERAGE DAILY
(US$) (US$) VOLUME (CN$) (CN$) VOLUME
----- ----- ------------- ------ ----- -------------
<S> <C> <C> <C> <C> <C> <C>
2001:
Quarter Ended March 31, 2001...... 66.75 52.30 977,648 102.85 78.19 8,941
Quarter Ended June 30, 2001....... 62.65 48.50 1,053,178 95.25 75.96 3,569
Quarter Ended September 30,
2001............................ 55.25 30.55 1,582,815 84.40 49.00 5,367
Quarter Ended December 31, 2001... 41.25 31.45 1,279,434 64.71 51.91 3,044
2002:
Quarter Ended March 31, 2002...... 49.10 34.40 1,197,478 77.46 54.70 12,353
Quarter Ended June 30, 2002....... 52.28 45.05 1,005,613 79.54 71.50 2,840
Quarter Ended September 30,
2002............................ 49.70 33.87 1,047,531 76.97 54.55 2,897
Quarter Ended December 31, 2002... 53.10 42.14 1,123,356 82.50 67.25 1,222
</Table>
DIVIDENDS
Devon commenced the payment of regular quarterly cash dividends on its
common stock on June 30, 1993, in the amount of $0.03 per share. Effective
December 31, 1996, Devon increased its quarterly dividend payment to $0.05 per
share. Devon anticipates continuing to pay regular quarterly dividends in the
foreseeable future. Dividends are also paid on the exchangeable shares at the
same rate and on the same dates as dividends paid on the common stock.
On February 25, 2003, there were 25,470 holders of record of Devon common
stock and 295 holders of record for the exchangeable shares.
23
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information (not covered by the
independent auditors' report) should be read in conjunction with "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations," and the consolidated financial statements and the notes thereto
included in "Item 8. Financial Statements and Supplementary Data." Note 2 to the
consolidated financial statements included in Item 8 of this report contains
information on mergers and acquisitions which occurred in 2002, 2001 and 2000,
as well as unaudited pro forma financial data for the years 2002 and 2001. Note
1 to the consolidated financial statements included in Item 8 contains
information on operations which were discontinued in 2002.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000 1999 1998
-------- ------- ------- ------- -------
(MILLIONS, EXCEPT PER SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C> <C>
OPERATING RESULTS
Oil sales............................................ $ 909 784 906 436 236
Gas sales............................................ 2,133 1,878 1,474 616 335
NGLs sales........................................... 275 131 154 68 25
Marketing and midstream revenues..................... 999 71 53 20 8
------ ----- ----- ----- -----
Total revenues.................................... 4,316 2,864 2,587 1,140 604
------ ----- ----- ----- -----
Lease operating expenses............................. 621 467 388 249 186
Transportation costs................................. 154 83 53 34 23
Production taxes..................................... 111 116 103 45 22
Marketing and midstream operating costs and
expenses.......................................... 808 47 28 10 3
Depreciation, depletion and amortization of property
and equipment..................................... 1,211 831 662 379 212
Amortization of goodwill............................. -- 34 41 16 --
General and administrative expenses.................. 219 114 96 83 48
Expenses related to mergers.......................... -- 1 60 17 13
Reduction of carrying value of oil and gas
properties........................................ 651 979 -- 476 354
------ ----- ----- ----- -----
Total operating costs and expenses................ 3,775 2,672 1,431 1,309 861
------ ----- ----- ----- -----
Earnings (loss) from operations...................... 541 192 1,156 (169) (257)
Interest expense..................................... (533) (220) (155) (115) (43)
Effects of changes in foreign currency exchange
rates............................................. 1 (11) (3) 13 (16)
Distributions on preferred securities of subsidiary
trust............................................. -- -- -- (7) (10)
Change in fair value of financial instruments........ 28 (2) -- -- --
Impairment of ChevronTexaco Corporation common
stock............................................. (205) -- -- -- --
Other income......................................... 34 69 40 10 22
------ ----- ----- ----- -----
Net other expenses................................ (675) (164) (118) (99) (47)
------ ----- ----- ----- -----
Earnings (loss) from continuing operations before
income taxes and cumulative effect of change in
accounting principle.............................. (134) 28 1,038 (268) (304)
</Table>
24
<PAGE>
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000 1999 1998
-------- ------- ------- ------- -------
(MILLIONS, EXCEPT PER SHARE DATA AND RATIOS)
<S> <C> <C> <C> <C> <C>
Income tax expense (benefit):
Current........................................... $ 23 48 120 18 (5)
Deferred.......................................... (216) (43) 257 (93) (98)
------ ----- ----- ----- -----
Total............................................. (193) 5 377 (75) (103)
------ ----- ----- ----- -----
Earnings (loss) from continuing operations before
cumulative effect of change in accounting
principle......................................... 59 23 661 (193) (201)
Results of discontinued operations before income
taxes............................................. 54 56 104 63 (58)
Income tax expense (benefit)......................... 9 25 35 24 (23)
------ ----- ----- ----- -----
Net results of discontinued operations............... 45 31 69 39 (35)
------ ----- ----- ----- -----
Earnings (loss) before cumulative effect of change in
accounting principle.............................. 104 54 730 (154) (236)
Cumulative effect of change in accounting
principle......................................... -- 49 -- -- --
------ ----- ----- ----- -----
Net earnings (loss).................................. $ 104 103 730 (154) (236)
====== ===== ===== ===== =====
Net earnings (loss) applicable to common
stockholders...................................... $ 94 93 720 (158) (236)
====== ===== ===== ===== =====
Basic net earnings (loss) per share:
Earnings (loss) from continuing operations........ $ 0.32 0.09 5.13 (2.13) (2.83)
Net results of discontinued operations............ $ 0.29 0.25 0.53 0.45 (0.49)
Cumulative effect of change in accounting
principle....................................... $ -- 0.39 -- -- --
------ ----- ----- ----- -----
Net earnings (loss)............................... $ 0.61 0.73 5.66 (1.68) (3.32)
====== ===== ===== ===== =====
Diluted net earnings (loss) per share:
Earnings (loss) from continuing operations........ $ 0.32 0.09 4.97 (2.13) (2.83)
Net results of discontinued operations............ $ 0.29 0.25 0.53 0.45 (0.49)
Cumulative effect of change in accounting
principle....................................... $ -- 0.38 -- -- --
------ ----- ----- ----- -----
Net earnings (loss)............................... $ 0.61 0.72 5.50 (1.68) (3.32)
====== ===== ===== ===== =====
Cash dividends per common share(1)................... $ 0.20 0.20 0.17 0.14 0.10
Weighted average common shares outstanding:
Basic............................................. 155 128 127 94 71
Diluted........................................... 156 130 132 99 77
Ratio of earnings to fixed charges(2)................ N/A 1.12 7.34 N/A N/A
Ratio of earnings to combined fixed charges and
preferred stock dividends(2)...................... N/A 1.05 6.70 N/A N/A
</Table>
<Table>
<Caption>
DECEMBER 31,
--------------------------------------------
2002 2001 2000 1999 1998
------- ------- ------ ------ ------
(MILLIONS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA
Total assets.................................. $16,225 13,184 6,860 6,096 1,931
Debentures exchangeable into shares of
ChevronTexaco Corporation common stock..... $ 662 649 760 760 --
Other long-term debt.......................... $ 6,900 5,940 1,289 1,656 736
Convertible preferred securities of subsidiary
trust...................................... $ -- -- -- -- 149
Stockholders' equity.......................... $ 4,653 3,259 3,277 2,521 750
</Table>
25
<PAGE>
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
---------------------------------------------
2002 2001 2000 1999 1998
------- ------- ------- ------ ------
(MILLIONS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
CASH FLOW DATA
Net cash provided by operating activities.... $ 1,754 1,910 1,589 539 330
Net cash used in investing activities........ $(2,046) (5,285) (1,173) (768) (607)
Net cash provided by (used in) financing
activities................................ $ 401 3,370 (390) 377 256
PRODUCTION, PRICE AND OTHER DATA(3)
Production:
Oil (MMBbls).............................. 42 36 37 25 20
Gas (Bcf)................................. 761 489 417 295 189
NGLs (MMBbls)............................. 19 8 7 5 3
MMBoe(4).................................. 188 126 113 79 55
Average prices:
Oil (Per Bbl)............................. $ 21.71 21.41 24.99 17.78 12.28
Gas (Per Mcf)............................. $ 2.80 3.84 3.53 2.09 1.78
NGLs (Per Bbl)............................ $ 14.05 16.99 20.87 13.28 8.08
Per Bo(4)................................. $ 17.61 22.19 22.38 14.22 11.09
Costs per Boe(4):
Operating costs........................... $ 4.71 5.29 4.81 4.15 4.29
Depreciation, depletion and amortization
of oil and gas properties............... $ 5.88 6.30 5.58 4.60 3.72
</Table>
- ---------------
(1) Devon acquired other entities via mergers in 1998 and 2000, and both mergers
were accounted for using the pooling-of-interests method of accounting for
business combinations. Therefore, the cash dividends per share presented for
1998 through 2000 are not representative of the actual amounts paid by Devon
on an historical basis. For the years 1998 through 2000, Devon's historical
cash dividends per share were $0.20 in each year.
(2) For purposes of calculating the ratio of earnings to fixed charges and the
ratio of earnings to combined fixed charges and preferred stock dividends,
(i) earnings consist of earnings before income taxes, plus fixed charges;
(ii) fixed charges consist of interest expense, distributions on preferred
securities of subsidiary trust, amortization of costs relating to
indebtedness and the preferred securities of subsidiary trust, and one-third
of rental expense estimated to be attributable to interest; and (iii)
preferred stock dividends consist of the amount of pre-tax earnings required
to pay dividends on the outstanding preferred stock. For the years 2002,
1999 and 1998, earnings were insufficient to cover fixed charges by $135
million, $264 million and $305 million, respectively. For the years 2002,
1999 and 1998, earnings were insufficient to cover combined fixed charges
and preferred stock dividends by $151 million, $270 million and $305
million, respectively.
(3) The preceding production, price and other data exclude the amounts related
to discontinued operations for all periods presented.
(4) Gas volumes are converted to Boe 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. NGL volumes are converted to Boe on a one-to-one basis with oil.
The respective prices of oil, gas and NGLs are affected by market and other
factors in addition to relative energy content.
26
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis addresses changes in Devon's
financial condition and results of operations during the three year period of
2000 through 2002. Reference is made to "Item 6. Selected Financial Data" and
"Item 8. Financial Statements and Supplementary Data."
OVERVIEW
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. The Mitchell merger added approximately 404 million Boe to Devon's
proved reserves.
Following the Mitchell merger announcement in August 2001, Devon announced
on September 4, 2001, that it had entered into an agreement to acquire Anderson
Exploration Ltd. ("Anderson") for approximately $3.5 billion in cash. This
acquisition closed on October 15, 2001, and therefore had an impact on Devon's
results for the last two and one-half months of 2001. The Anderson acquisition
added approximately 534 million Boe to Devon's proved reserves.
To fund the cash portions of these two acquisitions, as well as to pay
related transaction costs and retire certain long-term debt assumed from
Mitchell and Anderson, Devon entered into long-term debt agreements in October
2001 that totaled $6 billion. Half of this total consisted of $3 billion of
notes and debentures issued on October 3, 2001. Of this total, $1.25 billion
bears interest at 7.875% and matures in September 2031. The remaining $1.75
billion bears interest at 6.875% and matures in September 2011.
The remaining $3 billion of the $6 billion of long-term debt is in the form
of a credit facility that bears interest at floating rates. As of December 31,
2002, $1.9 billion of the original $3 billion balance had been 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 $1.4 billion
from the sale of certain oil and gas properties, of which $1.1 billion was used
to pay down debt. As of December 31, 2002, the balance outstanding under the
term loan credit facility was $1.1 billion at an average rate of 2.5%. Principal
payments due on this debt are $0.3 billion in April 2006 and $0.8 billion in
October 2006.
The Mitchell and Anderson acquisitions followed another significant
acquisition. In August 2000, Devon closed its merger with Santa Fe Snyder
Corporation. This transaction added approximately 386 million Boe to Devon's
proved reserves.
In addition to the mergers and acquisitions, Devon's exploration and
development efforts have also been significant contributors to Devon's growth.
In 2002, Devon spent $1.5 billion in its exploration, drilling and development
efforts. These costs included drilling 1,685 wells, of which 1,599 were
completed as producers. In 2000 and 2001, Devon spent an aggregate of $2.0
billion in its exploration, drilling and development efforts. These costs
included drilling 2,873 wells, of which 2,705 were completed as producers.
The following statistics illustrate the effects that Devon's mergers and
acquisitions and its drilling and development activities have had on operations
during the last three years. This data compares Devon's 2002 results to those of
2000 for Devon combined with Santa Fe Snyder, which was acquired in a merger
accounted for under the pooling-of-interests method. Such comparison yields the
following fluctuations:
- Proved reserves increased 651 million Boe, or 68%.
- Combined oil, gas and NGL production increased 75 million Boe, or 66%.
- Total revenues increased $1.7 billion, or 67%.
- Net cash provided by operating activities increased $165 million, or 10%.
27
<PAGE>
During 2002, Devon marked its 14th anniversary as a public company. While
Devon has consistently increased production over this 14-year period, volatility
in oil, gas and NGL prices has resulted in considerable variability in earnings
and cash flows. Prices for oil, natural gas and NGLs are determined primarily by
market conditions. Market conditions for these products have been, and will
continue to be, influenced by regional and worldwide economic activity, weather
and other factors that are beyond Devon's control. Devon's future earnings and
cash flows will continue to depend on market conditions.
Like all oil and gas exploration and production companies, Devon faces the
challenge of natural production decline. As initial pressures are depleted, oil
and gas production from a given well naturally decreases. Thus, an oil and gas
exploration and production company depletes part of its asset base with each
unit of oil or gas it produces. Historically, Devon has been able to overcome
this natural decline by adding, through drilling and acquisitions, more reserves
than it produces. Devon's future growth, if any, will depend on its ability to
continue to add reserves in excess of production.
Because oil, gas and NGL prices are influenced by many factors outside of
its control, Devon's management has focused its efforts on increasing oil and
gas reserves and production and controlling expenses. Over its 14-year history
as a public company, Devon has been able to reduce its controllable operating
costs per unit of production. Devon's future earnings and cash flows are
dependent on its ability to continue to contain operating costs at levels that
allow for profitable production.
RESULTS OF OPERATIONS
REVENUES
Changes in oil, gas and NGL production, prices and revenues from 2000 to
2002 are shown in the following tables. (Unless otherwise stated, all dollar
amounts in this report are expressed in U.S. dollars.)
<Table>
<Caption>
TOTAL
------------------------------------------
YEAR ENDED DECEMBER 31,
------------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C>
Production
Oil (MMBbls)................. 42 +17% 36 -3% 37
Gas (Bcf).................... 761 +56% 489 +17% 417
NGLs (MMBbls)................ 19 +138% 8 +14% 7
Oil, gas and NGLs (MMBoe).... 188 +50% 126 +12% 113
Average Prices
Oil (per Bbl)................ $21.71 +1% 21.41 -14% 24.99
Gas (per Mcf)................ $ 2.80 -27% 3.84 +9% 3.53
NGLs (per Bbl)............... $14.05 -17% 16.99 -19% 20.87
Oil, gas and NGLs (per
Boe)...................... $17.61 -21% 22.19 -1% 22.38
Revenues ($ in millions)
Oil.......................... $ 909 +16% 784 -13% 906
Gas.......................... $2,133 +14% 1,878 +27% 1,474
NGLs......................... $ 275 +110% 131 -15% 154
------ ----- -----
Oil, gas and NGLs............ $3,317 +19% 2,793 +10% 2,534
====== ===== =====
</Table>
28
<PAGE>
<Table>
<Caption>
DOMESTIC
------------------------------------------
YEAR ENDED DECEMBER 31,
------------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C>
Production
Oil (MMBbls)................. 24 -8% 26 -10% 29
Gas (Bcf).................... 482 +28% 376 +6% 355
NGLs (MMBbls)................ 14 +133% 6 +0% 6
Oil, gas and NGLs (MMBoe).... 118 +24% 95 +1% 94
Average Prices
Oil (per Bbl)................ $21.99 -2% 22.36 -12% 25.45
Gas (per Mcf)................ $ 2.91 -30% 4.17 +14% 3.67
NGLs (per Bbl)............... $13.37 -22% 17.15 -16% 20.30
Oil, gas and NGLs (per
Boe)...................... $17.87 -25% 23.80 +4% 22.95
Revenues ($ in millions)
Oil.......................... $ 524 -11% 586 -19% 727
Gas.......................... $1,403 -11% 1,571 +20% 1,305
NGLs......................... $ 192 +86% 103 -24% 136
------ ----- -----
Oil, gas and NGLs............ $2,119 -6% 2,260 +4% 2,168
====== ===== =====
</Table>
<Table>
<Caption>
CANADA
------------------------------------------
YEAR ENDED DECEMBER 31,
------------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C>
Production
Oil (MMBbls)................. 16 +100% 8 +60% 5
Gas (Bcf).................... 279 +147% 113 +82% 62
NGLs (MMBbls)................ 5 +150% 2 +100% 1
Oil, gas and NGLs (MMBoe).... 68 +134% 29 +81% 16
Average Prices
Oil (per Bbl)................ $21.00 +18% 17.84 -27% 24.46
Gas (per Mcf)................ $ 2.62 -4% 2.73 +1% 2.71
NGLs (per Bbl)............... $15.93 -3% 16.43 -38% 26.51
Oil, gas and NGLs (per
Boe)...................... $16.96 +1% 16.80 -12% 19.18
Revenues ($ in millions)
Oil.......................... $ 331 +127% 146 +26% 116
Gas.......................... $ 730 +138% 307 +82% 169
NGLs......................... $ 83 +196% 28 +56% 18
------ ----- -----
Oil, gas and NGLs............ $1,144 +138% 481 +59% 303
====== ===== =====
</Table>
29
<PAGE>
<Table>
<Caption>
INTERNATIONAL
--------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C>
Production
Oil (MMBbls)..................................... 2 +0% 2 -33% 3
Gas (Bcf)........................................ -- N/M -- N/M --
NGLs (MMBbls).................................... -- N/M -- N/M --
Oil, gas and NGLs (MMBoe)........................ 2 +0% 2 -33% 3
Average Prices
Oil (per Bbl).................................... $23.70 +1% 23.42 +9% 21.44
Gas (per Mcf).................................... $ -- N/M -- N/M --
NGLs (per Bbl)................................... $ -- N/M -- N/M --
Oil, gas and NGLs (per Boe)...................... $23.70 +1% 23.42 +9% 21.44
Revenues ($ in millions)
Oil.............................................. $ 54 +4% 52 -17% 63
Gas.............................................. $ -- N/M -- N/M --
NGLs............................................. $ -- N/M -- N/M --
------ ----- -----
Oil, gas and NGLs................................ $ 54 +4% 52 -17% 63
====== ===== =====
</Table>
The average prices shown in the preceding tables include the effect of
Devon's oil and gas commodity hedging activities. Following is a comparison of
Devon's average prices with and without the effect of hedges for each of the
last three years.
<Table>
<Caption>
WITH HEDGES WITHOUT HEDGES
------------------------ ------------------------
2002 2001 2000 2002 2001 2000
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Oil (per Bbl)..................... $21.71 21.41 24.99 22.63 21.79 26.00
Gas (per Mcf)..................... $ 2.80 3.84 3.53 2.70 3.89 3.61
NGLs (per Bbl).................... $14.05 16.99 20.87 14.05 16.99 20.87
Oil, gas and NGLs (per Boe)....... $17.61 22.19 22.38 17.36 22.48 23.01
</Table>
OIL REVENUES
2002 vs. 2001 Oil revenues increased $125 million in 2002. An increase in
production of 6 million barrels caused oil revenues to increase by $112 million.
The Anderson and Mitchell acquisitions accounted for 11 million barrels of
increased production. This was partially offset by the effect of divestitures,
which reduced 2002 production by 5 million barrels. A $0.30 per barrel increase
in the average oil price in 2002 accounted for the remaining $13 million of
increased oil revenues.
2001 vs. 2000 Oil revenues decreased $122 million in 2001. A $3.58 per
barrel decrease in 2001's average price caused revenues to drop by $114 million.
A decrease in production of one million barrels caused oil revenues to decrease
by an additional $8 million. The October 2001 Anderson merger accounted for
three million barrels of 2001 production. However, oil production from Devon's
other properties declined four million barrels. This reduction was primarily the
result of domestic and international properties which were sold prior to 2001
but whose production was included in 2000 prior to the sales.
GAS REVENUES
2002 vs. 2001 Gas revenues increased $255 million in 2002. An increase in
production of 272 Bcf caused gas revenues to increase by $1.0 billion. The
Anderson and Mitchell acquisitions accounted for 323 Bcf of increased
production. This was partially offset by the effect of divestitures, which
reduced 2002
30
<PAGE>
production by 30 Bcf, and by natural declines in production. The effects of the
net production increase were partially offset by a $1.04 per Mcf decrease in the
average gas price in 2002.
2001 vs. 2000 Gas revenues increased $404 million in 2001. Of this total
increase, $253 million was due to a 72 Bcf increase in production in 2001. The
October 2001 Anderson merger accounted for 51 Bcf of the increase. Production
from Devon's domestic properties increased 21 Bcf, due primarily to drilling and
development in Devon's coalbed methane properties as well as the acquisition of
certain properties in the second quarter of 2001. A $0.31 per Mcf increase in
the average gas price in 2001 accounted for the remaining $151 million of
increased gas revenues.
NGL REVENUES
2002 vs. 2001 NGL revenues increased $144 million in 2002. An 11 million
barrel increase in 2002 production caused revenues to increase $202 million. The
Anderson and Mitchell acquisitions accounted for 12 million barrels of increased
production. This was partially offset by production lost from divestitures. The
effects of the net production increase were partially offset by a $2.94 per
barrel decrease in the average NGL price in 2002.
2001 vs. 2000 NGL revenues decreased $23 million in 2001. A decrease in
2001's average price of $3.88 per barrel caused NGL revenues to decrease $30
million. This was partially offset by a $7 million increase related to a
production increase of one million barrels. The October 2001 Anderson merger
accounted for all of the increase.
MARKETING AND MIDSTREAM REVENUES
2002 vs. 2001 Marketing and midstream revenues increased $928 million in
2002. The Mitchell acquisition included significant marketing and midstream
assets which accounted for substantially all of the increase in revenues.
2001 vs. 2000 Marketing and midstream revenues increased $18 million in
2001. This increase was primarily the result of capacity additions to Devon's
Wyoming gas pipeline systems.
31
<PAGE>
OPERATING COSTS AND EXPENSES
The details of the changes in operating costs and expenses between 2000 and
2002 are shown in the table below.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
------ ------- ----- ------- -----
<S> <C> <C> <C> <C> <C>
Operating costs and expenses ($ in
millions):
Production and operating expenses:
Lease operating expenses............. $ 621 +33% 467 +20% 388
Transportation costs................. 154 +86% 83 +57% 53
Production taxes..................... 111 -4% 116 +13% 103
Depreciation, depletion and amortization
of oil and gas properties............ 1,106 +39% 793 +25% 632
Amortization of goodwill................ -- -100% 34 -17% 41
------ ----- -----
Subtotal........................... 1,992 +33% 1,493 +23% 1,217
Marketing and midstream operating costs
and expenses......................... 808 +1,619% 47 +68% 28
Depreciation and amortization of non-oil
and gas properties................... 105 +176% 38 +27% 30
General and administrative expenses..... 219 +92% 114 +19% 96
Expenses related to mergers............. -- -100% 1 -98% 60
Reduction of carrying value of oil and
gas properties....................... 651 -34% 979 N/M --
------ ----- -----
Total.............................. $3,775 +41% 2,672 +87% 1,431
====== ===== =====
Operating costs and expenses per Boe:
Production and operating expenses:
Lease operating expenses............. $ 3.30 -11% 3.71 +8% 3.43
Transportation costs................. 0.82 +24% 0.66 +40% 0.47
Production taxes..................... 0.59 -36% 0.92 +1% 0.91
Depreciation, depletion and amortization
of oil and gas properties............ 5.88 -7% 6.30 +13% 5.58
Amortization of goodwill................ -- -100% 0.27 -27% 0.37
------ ----- -----
Subtotal........................... 10.59 -11% 11.86 +10% 10.76
Marketing and midstream operating costs
and expenses(1)...................... 4.29 +1,059% 0.37 +48% 0.25
Depreciation and amortization of non-oil
and gas properties(1)................ 0.55 +83% 0.30 +11% 0.27
General and administrative
expenses(1).......................... 1.16 +27% 0.91 +7% 0.85
Expenses related to mergers(1).......... -- -100% 0.01 -98% 0.53
Reduction of carrying value of oil and
gas properties(1).................... 3.45 -56% 7.78 N/M --
------ ----- -----
Total.............................. $20.04 -6% 21.23 +68% 12.66
====== ===== =====
</Table>
- ---------------
(1) Though per Boe amounts for these expense items may be helpful for
profitability trend analysis, these expenses are not directly attributable
to production volumes.
N/M -- Not meaningful.
32
<PAGE>
OIL, GAS AND NGLS PRODUCTION AND OPERATING EXPENSES
The details of the changes in production and operating expenses related to
oil, gas and NGLs producing activities between 2000 and 2002 are shown in the
table below.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
----------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
----- ------- ---- ------- ----
<S> <C> <C> <C> <C> <C>
Expenses ($ in millions):
Lease operating expenses..................... $ 621 +33% 467 +20% 388
Transportation costs......................... 154 +86% 83 +57% 53
Production taxes............................. 111 -4% 116 +13% 103
----- ---- ----
Total production and operating expenses... $ 886 +33% 666 +22% 544
===== ==== ====
Expenses per Boe:
Lease operating expenses..................... $3.30 -11% 3.71 +8% 3.43
Transportation costs......................... 0.82 +24% 0.66 +40% 0.47
Production taxes............................. 0.59 -36% 0.92 +1% 0.91
----- ---- ----
Total production and operating expenses... $4.71 -11% 5.29 +10% 4.81
===== ==== ====
</Table>
2002 vs. 2001 Lease operating expenses increased $154 million in 2002. The
Anderson and Mitchell acquisitions accounted for $210 million of the increase.
The historical Devon lease operating expenses decreased $56 million primarily
due to divestitures. The drop in lease operating expenses per Boe from $3.71 in
2001 to $3.30 in 2002 was primarily related to the lower cost properties
acquired in the Anderson and Mitchell acquisitions and the divestiture of some
of Devon's higher cost properties.
Transportation costs represent those costs paid directly to third-party
providers to transport oil, gas and NGL production sold downstream from the
wellhead. Transportation costs increased $71 million in 2002 primarily due to an
increase in gas production from the Anderson and Mitchell acquisitions.
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 6% decrease in domestic oil, gas
and NGLs revenues was the primary cause of a 4% decrease in production taxes.
2001 vs. 2000 Recurring lease operating expenses increased $79 million in
2001. The Anderson acquisition accounted for $47 million of the increase in
expenses. The remaining increase in recurring costs was primarily caused by
higher third-party service, fuel and electricity costs.
Transportation costs increased $30 million in 2001. Of this increase, $12
million related to the Anderson acquisition. The remainder of the increase was
primarily due to an increase in gas production from Devon's domestic drilling
and development activities.
As previously stated, most of the U.S. production taxes are based on a
fixed percentage of revenues. Therefore, the 4% increase in domestic oil, gas
and NGL revenues was the primary cause of a 11% increase in domestic production
taxes. Production taxes did not increase proportionately to the increase in
revenues. This was primarily due to the fact that most of the increase in
domestic revenues occurred in the Western division which has higher production
tax rates than the other domestic divisions.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A")
DD&A of oil and gas properties is calculated as the percentage of total
proved reserve volumes produced during the year, multiplied by the net
capitalized investment in those reserves including estimated future development
and dismantlement and abandonment costs (the "depletable base"). Generally, if
reserve volumes are revised up or down, then the DD&A rate per unit of
production will change inversely. However, if the depletable base changes, then
the DD&A rate moves in the same direction. The per unit DD&A rate is not
affected by production volumes. Absolute or total DD&A, as
33
<PAGE>
opposed to the rate per unit of production, generally moves in the same
direction as production volumes. Oil and gas property DD&A is calculated
separately on a country-by-country basis.
2002 vs. 2001 Oil and gas property related DD&A increased $313 million in
2002. A 50% increase in 2002's oil, gas and NGLs production caused DD&A to
increase $394 million. The effects of the production increase were partially
offset by a decrease in the combined U.S., Canadian and international DD&A rate
from $6.30 per Boe in 2001 to $5.88 per Boe in 2002. The drop in the DD&A rate
was primarily due to reductions of carrying value of oil and gas properties
recorded in the fourth quarter of 2001 and the second quarter of 2002.
Non-oil and gas property DD&A increased $67 million in 2002 compared to
2001. Depreciation of the marketing and midstream assets acquired in the January
2002 Mitchell acquisition accounted for substantially all of the increase.
2001 vs. 2000 Oil and gas property related DD&A increased $161 million in
2001. Of this total increase, $70 million was due to the 12% increase in oil,
gas and NGLs production in 2001. The remaining $91 million increase was due to
an increase in the consolidated DD&A rate. This rate increased from $5.58 per
Boe in 2000 to $6.30 per Boe in 2001.
Non-oil and gas property DD&A increased $8 million in 2001 compared to
2000. Depreciation of Devon's Wyoming gas pipeline systems accounted for the
2001 increase.
AMORTIZATION OF 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 as they were prior
to 2002, but are instead tested for impairment at least annually. Prior to the
adoption of SFAS No. 142, Devon's goodwill amortization was $34 million and $41
million in 2001 and 2000, respectively.
MARKETING AND MIDSTREAM OPERATING COSTS AND EXPENSES
2002 vs. 2001 Marketing and midstream operating costs and expenses
increased $761 million in 2002. The Mitchell acquisition included significant
marketing and midstream assets which accounted for substantially all of the
increase in revenues.
2001 vs. 2000 Marketing and midstream operating costs and expenses
increased $19 million in 2001. This increase was primarily the result of
capacity additions to Devon's Wyoming gas pipeline systems.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A")
Devon's net G&A consists of three primary components. The largest of these
components is the gross amount of expenses incurred for personnel costs, office
expenses, professional fees and other G&A items. The gross amount of these
expenses is partially reduced by two offsetting components. One is the amount of
G&A capitalized pursuant to the full cost method of accounting. The other is the
amount of G&A reimbursed by working interest owners of properties for which
Devon serves as the operator. These reimbursements are received during both the
drilling and operational stages of a property's life. The gross amount of G&A
incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in
the consolidated statements of operations. Net G&A includes expenses related to
oil, gas and NGL exploration
34
<PAGE>
and production activities, as well as marketing and midstream activities. See
the following table for a summary of G&A expenses by component.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
--------------------------------------
2002 2001
2002 VS 2001 2001 VS 2000 2000
---- ------- ---- ------- ----
($ IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Gross G&A........................................ $387 +56% 248 +19% 209
Capitalized G&A.................................. (97) +26% (77) +24% (62)
Reimbursed G&A................................... (71) +25% (57) +12% (51)
---- --- ---
Net G&A........................................ $219 +92% 114 +19% 96
==== === ===
</Table>
2002 vs. 2001 Gross G&A increased $139 million primarily due to additional
costs incurred as a result of the Anderson and Mitchell acquisitions. Also
included in 2002's gross G&A was $13 million related to the abandonment of
certain office space assumed in the Santa Fe Snyder merger. G&A was reduced $20
million due to an increase in the amount capitalized as part of oil and gas
properties. G&A was also reduced $14 million by an increase in the amount of
reimbursements on operated properties. Changes in both of the capitalized and
reimbursed amounts were primarily related to the Anderson and Mitchell
acquisitions.
2001 vs. 2000 Gross G&A increased $39 million primarily due to additional
costs incurred as a result of the Anderson acquisition and additional personnel
related costs. G&A was reduced $15 million due to an increase in the amount
capitalized. The increase in capitalized G&A was primarily related to additional
personnel related costs and increased acquisition, exploration and development
activities. G&A was also reduced $6 million by an increase in the amount of
reimbursements on operated properties. The increase in reimbursed G&A was
primarily related to an increase in the number of operated properties.
EXPENSES RELATED TO MERGERS
Approximately $1 million of expenses were incurred in 2001 in connection
with the Anderson acquisition. These costs related to Devon employees who were
terminated as part of the Anderson acquisition.
Approximately $60 million of expenses were incurred in 2000 in connection
with the Santa Fe Snyder merger. These expenses consisted primarily of severance
and other benefit costs, investment banking fees, other professional expenses,
costs associated with duplicate facilities and various transaction related
costs. The pooling-of-interests method of accounting for business combinations
required such costs to be expensed as opposed to capitalized as costs of the
transaction.
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, may not exceed a calculated
"ceiling." The ceiling limitation is the discounted estimated after-tax future
net revenues from proved 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. The calculation also dictates the use of
a 10% discount factor. 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
35
<PAGE>
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.
During 2002 and 2001, Devon reduced the carrying value of its oil and gas
properties by $651 and $883 million, respectively, due to the full cost ceiling
limitations. The after-tax effect of these reductions in 2002 and 2001 was $371
million and $533 million, respectively. The following table summarizes these
reductions by country.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------------
2002 2001
-------------- --------------
NET OF NET OF
GROSS TAXES GROSS TAXES
----- ------ ----- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
United States........................................... $ -- -- 449 281
Canada.................................................. 651 371 434 252
---- --- --- ---
Total................................................. $651 371 883 533
==== === === ===
</Table>
The 2002 Canadian reduction was primarily the result of lower prices. 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, gas and NGL 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 recorded fair values of oil and gas properties added from the
Anderson acquisition in 2001 were based on expected future oil and gas prices
that were higher than the June 30, 2002, prices used to calculate the Canadian
ceiling.
Based on oil, natural gas and NGL 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 end of June 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 MMBtu. 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.
The 2001 domestic and Canadian reductions were also primarily the result of
lower prices. The oil and gas properties added from the Anderson acquisition and
other smaller acquisitions in 2001 were recorded at fair values that were based
on expected future oil and gas prices higher than the December 31, 2001 prices
used to calculate the ceiling. The year-end 2001 prices used to calculate the
ceiling were based on a NYMEX oil price of $19.84 per barrel, a Henry Hub gas
price of $2.65 per MMBtu and an AECO gas price of C$3.67 per MMBtu.
Additionally, during 2001, Devon elected to abandon 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, Devon recorded a $96 million charge associated with the impairment
of these properties. The after-tax effect of this reduction was $78 million.
The provisions of SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets, which Devon was required to adopt effective January 1,
2002, are only required to be applied prospectively. As a result, these
impairment charges have not been reclassified as part of the Discontinued
Operations on the consolidated statements of operations.
36
<PAGE>
OTHER INCOME (EXPENSES)
The details of the changes in other income (expenses) between 2000 and 2002
are shown in the table below.
<Table>
<Caption>
2002 2001 2000
----- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Other income (expenses):
Interest expense:
Interest based on debt outstanding..................... $(499) (200) (157)
(Accretion) amortization of debt (discount) premium,
net.................................................. (13) (10) 4
Facility and agency fees............................... (2) (1) (3)
Amortization of capitalized loan costs................. (8) (3) (2)
Capitalized interest................................... 4 3 3
Early retirement premiums.............................. (8) (7) --
Other.................................................. (7) (2) --
----- ---- ----
Total interest expense............................ (533) (220) (155)
Effects of changes in foreign currency exchange
rates................................................ 1 (11) (3)
Change in fair value of financial instruments.......... 28 (2) --
Impairment of ChevronTexaco Corporation common stock... (205) -- --
Other income........................................... 34 69 40
----- ---- ----
Total................................................ $(675) (164) (118)
===== ==== ====
</Table>
INTEREST EXPENSE
2002 vs. 2001 Interest expense increased $313 million in 2002. An increase
in the average debt balance outstanding from $3.0 billion in 2001 to $8.3
billion in 2002 caused interest expense to increase $319 million. The increase
in average debt outstanding was attributable primarily to the long-term debt
issued and assumed as a result of the Mitchell and Anderson acquisitions.
The average interest rate on outstanding debt decreased from 6.6% in 2001
to 6.0% in 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 2002. The overall rate decrease caused interest expense to decrease $20
million in 2002. Other items included in interest expense that are not related
to the debt balance outstanding were $14 million higher in 2002. Items not
related to the balance of debt outstanding include early retirement premiums,
facility and agency fees, amortization of costs and other miscellaneous items.
Of the $14 million increase in other items during 2002, $5 million related to
the amortization of capitalized loan costs and $3 million related to an increase
in the accretion of debt discounts. These increases were primarily due to the
additional debt incurred as a result of the Mitchell and Anderson acquisitions.
2001 vs. 2000 Interest expense increased $65 million in 2001. Of this
total increase, $44 million was caused by an increase in the average debt
balance outstanding from $2.3 billion in 2000 to $3.0 billion in 2001. The
increase in average debt outstanding was attributable primarily to the long-term
debt issued and assumed as a result of the October 2001 Anderson acquisition.
The average interest rate on outstanding debt decreased from 6.7% in 2000
to 6.6% in 2001. This rate decrease caused interest expense to decrease $1
million in 2001. Other items included in interest expense that are not related
to the debt balance outstanding were $22 million higher in 2001 compared to
2000. The increase in other items was primarily related to an increase in
accretion of discounts and a $7 million loss related to an early retirement
premium.
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<PAGE>
The increase in accretion of debt discounts in 2001 was related to the
adoption of Statement of Financial Accounting Standards No. 133 ("SFAS No. 133")
effective January 1, 2001. Devon's debentures that are exchangeable into shares
of ChevronTexaco Corporation ("ChevronTexaco") common stock were revalued as of
August 17, 1999. This is the date the debentures were assumed as part of the
PennzEnergy merger. Under SFAS No. 133, the total fair value of the debentures
was allocated between the interest-bearing debt and the option to exchange
ChevronTexaco common stock that is embedded in the debentures. Accordingly, the
debt portion of the debentures was reduced by $140 million as of August 17,
1999. This discount is being accreted in interest expense, which has raised the
effective interest rate on the debentures to 7.76% in 2001 compared to 4.92%
recorded prior to 2001. The accretion in 2001 was $12 million.
EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES
2002 vs. 2001 As a result of the Anderson acquisition, a 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 $0.628 at December 31, 2001 to $0.633 at December 31, 2002
resulted in a $1 million gain. The drop in the Canadian-to-U.S. dollar exchange
rate from $0.642 at October 15, 2001 (when the debt was assumed) to $0.628 at
December 31, 2001 resulted in an $11 million loss.
2001 vs. 2000 Until mid-January 2000, a Canadian subsidiary had certain
fixed-rate senior notes which were denominated in U.S. dollars. In mid-January
2000, these notes were retired prior to maturity. The Canadian-to-U.S. dollar
exchange rate dropped slightly in January prior to the debt retirement. As a
result, $3 million of expense was recognized in 2000.
CHANGE IN FAIR VALUE OF FINANCIAL INSTRUMENTS
2002 vs. 2001 As required under the provisions of SFAS No. 133, Accounting
for Derivative Instruments and Certain Hedging Activities and SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities, an
Amendment of SFAS No. 133, Devon records in its statements of operations the
change in fair value of derivative instruments that do not qualify for hedge
accounting treatment.
During 2002 and 2001, Devon recorded $20 million and $8 million,
respectively, of gains related to changes in fair value. The gains related
principally to the option embedded in Devon's debentures that are exchangeable
into shares of ChevronTexaco common stock. Also, Devon recorded an $8 million
net gain in 2002 and a $10 million net charge in 2001 related to the
ineffectiveness of the various cash flow hedges.
IMPAIRMENT OF CHEVRONTEXACO CORPORATION COMMON STOCK
Devon owns approximately 7.1 million common shares of ChevronTexaco. The
market value of these shares as of December 31, 2002, was approximately $472
million. Devon acquired these shares in its August 1999 acquisition of
PennzEnergy Company. The shares are deposited with an exchange agent for
possible exchange for $760 million of debentures that are exchangeable into the
ChevronTexaco shares. The debentures, which mature in August 2008, were also
assumed by Devon in the 1999 PennzEnergy acquisition.
Devon initially recorded the ChevronTexaco common shares at their market
value at the closing date of the PennzEnergy acquisition, which was $95.38 per
share, or an aggregate value of $677 million. Since then, as the ChevronTexaco
shares have fluctuated in market value, the value of the shares on Devon's
balance sheet has been adjusted to the applicable market value. Through
September 30, 2002, any decreases in the value of the ChevronTexaco common
shares were determined by Devon to be temporary
38
<PAGE>
in nature. Therefore, the changes in value were recorded directly to
stockholders' equity and were not recorded in Devon's results of operations
through September 30, 2002.
The determination that a decline in value of the ChevronTexaco shares is
temporary or other than temporary is subjective and influenced by many factors.
Among these factors are the significance of the decline as a percentage of the
original cost, the length of time the stock price has been below original cost,
the performance of the stock price in relation to the stock price of its
competitors within the industry and the market in general, and whether the
decline is attributable to specific adverse conditions affecting ChevronTexaco.
Beginning in July 2002, the market value of ChevronTexaco common stock
began what has ultimately become a significant decline. The price per share
decreased from $88.50 at June 30, 2002, to $69.25 per share at September 30,
2002, and to $66.48 per share at December 31, 2002. The year-end price of $66.48
represents a 25% decline since June 30, 2002, and a 30% decline from the
original valuation in August 1999. As a result of the continuation of the
decline in value during the fourth quarter of 2002, Devon determined that the
decline is other than temporary, as that term is defined by accounting rules.
Therefore, the $205 million cumulative decrease in the value of the
ChevronTexaco common shares from the initial acquisition in August 1999 to
December 31, 2002, was recorded as a noncash charge to Devon's results of
operations in the fourth quarter of 2002. Net of the applicable tax benefit, the
charge reduced net earnings by $128 million.
Depending on the future performance of ChevronTexaco's common stock, Devon
may be required to record additional noncash charges in future periods if Devon
determines that a decline in the value of such stock is other than temporary.
OTHER INCOME
2002 vs. 2001 Other income decreased $35 million, or 51% in 2002. Other
income in 2001 included a $30 million gain from the settlement of a foreign
exchange forward purchase contract entered into by Devon related to the funding
of the Anderson acquisition. This gain did not recur in 2002.
2001 vs. 2000 Other revenues increased $29 million, or 73% in 2001. As
discussed previously, 2001 other income included a $30 million gain from the
settlement of a foreign exchange forward purchase contract entered into by Devon
related to the funding of the Anderson acquisition.
INCOME TAXES
2001 vs. 2000 Devon's 2002 effective financial tax rate attributable to
continuing operations was a benefit of 144% compared to an effective financial
tax rate expense of 18% in 2001. Excluding the effects of the impairment of
ChevronTexaco stock in 2002 and the reduction of carrying value of oil and gas
properties in 2002 and 2001, the effective financial tax expense rates were 23%
and 37% in 2002 and 2001, respectively.
The 2002 rate, excluding the ChevronTexaco common stock impairment and the
oil and gas property writedown, was lower than the statutory federal tax rate
primarily due to the tax benefits of certain foreign deductions. The 2001 rate,
excluding the oil and gas property writedowns, 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.
2001 vs. 2000 Devon's 2001 and 2000 effective financial tax expense rates
were 18% and 36%, respectively. Excluding the effects of the reduction of
carrying value of oil and gas properties in 2001, the effective financial tax
expense rate was 37% in 2001. The 2001 rate was higher than the statutory
federal tax rate of 35% due to the effect of state taxes, goodwill amortization
that was not deductible for income tax purposes and the effect of foreign income
taxes. The 2000 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, offset in part by the
recognition of a benefit from the disposition of Devon's assets in Venezuela.
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<PAGE>
RESULTS OF 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. On October 25,
2002, Devon sold its Argentine operations to Petroleo Brasileiro S.A. for total
cash consideration of $90 million. On January 27, 2003, Devon sold its Egyptian
operations to IPR Transoil Corporation for total cash consideration of $7
million.
Under the provisions of SFAS No. 144, Devon has reclassified its
Indonesian, Argentine and Egyptian activities as discontinued operations. This
reclassification affects not only the 2002 presentation of financial results,
but also the presentation of all prior periods' results.
Following are the components of the net results of discontinued operations
for the years 2002, 2001 and 2000:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
--------------------
2002 2001 2000
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Net gain on sale of discontinued operations................. $31 -- --
Earnings from discontinued operations before income taxes... 23 56 104
Income tax expense.......................................... 9 25 35
--- -- ---
Net results of discontinued operations...................... $45 31 69
=== == ===
</Table>
2002 vs. 2001 The decrease in earnings from discontinued operations before
income taxes and the related income taxes from 2001 to 2002 was primarily due to
the sale of these operations during 2002.
2001 vs. 2000 The decrease in earnings from discontinued operations before
income taxes and the related income taxes from 2000 to 2001 was primarily due to
a decline in oil prices and the recognition of a $24 million reduction in the
carrying value of Egyptian oil and gas properties. The reduction in Egypt was
the result of high finding and development costs and negative revisions to
proved reserves.
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
At the time of adoption of SFAS No. 133, Devon recorded a
cumulative-effect-type adjustment to net earnings for a $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 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 elsewhere in this report.
CAPITAL EXPENDITURES
Approximately $3.4 billion was spent in 2002 for capital expenditures. This
total includes $1.7 billion related to the January 2002 Mitchell acquisition;
$1.6 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 2001 total expenditures of $5.2 billion ($3.5 billion
of which related to the October 2001 Anderson acquisition and $1.6 billion of
which was related to other acquisitions and the drilling or
40
<PAGE>
development of oil and gas properties) and 2000 total expenditures of $1.1
billion ($1.0 billion of which was related to the drilling or development of oil
and gas properties.)
OTHER CASH USES
Devon's common stock dividends were $31 million, $25 million and $22
million in 2002, 2001 and 2000, respectively. Devon also paid $10 million of
preferred stock dividends in 2002, 2001 and 2000.
During 2001, Devon repurchased 3,754,000 shares of common stock at an
aggregate cost of $190 million or $50.71 per share. Devon also repurchased
shares of its common stock in 2001 under an odd-lot repurchase program. Pursuant
to this program, Devon purchased and retired 232,000 shares of its common stock
for a total cost of $14 million, or $57.40 per share.
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 was $1.4 billion generated from sales of oil and gas
properties.
Operating Cash Flow
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 activity, 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 January
31, 2003.
<Table>
<Caption>
FIXED-PRICE PHYSICAL PRICE SWAP PRICE
DELIVERY CONTRACTS CONTRACTS COLLARS TOTAL
-------------------- ---------- ------- -----
<S> <C> <C> <C> <C>
Oil production (MMBbls)
2003.................................... -- -- 20 20
2004.................................... -- -- 1 1
Natural gas production (Bcf)
2003.................................... 16 35 239 290
2004.................................... 16 -- 47 63
</Table>
In addition to the above quantities, Devon also has fixed-price physical
delivery contracts, for the years 2005 through 2011, covering Canadian natural
gas production ranging from 8 Bcf to 14 Bcf per year. From 2012 through 2016,
Devon also has Canadian gas volumes subject to fixed-price contracts, but the
yearly volumes are less than 1 Bcf.
By removing the price volatility from a portion of its oil and natural gas
production, Devon has mitigated, but not eliminated, the potential negative
effect of declining prices on its operating cash flow. The combination of
fixed-price contracts, price swaps and price collars currently in place
represents approximately 55% of estimated 2003 oil production and 39% of
estimated 2003 natural gas production.
It is Devon's policy to only enter into derivative contracts with
investment grade rated counterparties deemed by management as competent and
competitive market makers.
41
<PAGE>
In December 2002, Devon announced that its capital expenditure budget for
the year 2003 was approximately $1.8 billion. This capital budget represents the
largest planned use of available operating cash flow. To a certain degree, the
ultimate timing of these capital expenditures is within Devon's control.
Therefore, if oil and natural gas prices decline to levels below its acceptable
levels, Devon could choose to defer a portion of these planned 2003 capital
expenditures until later periods to achieve the desired balance between sources
and uses of liquidity. Based upon current oil and gas price expectations for
2003, Devon anticipates that its operating cash flow will exceed its planned
capital expenditures and other cash requirements for the year. Devon currently
intends to accumulate any excess cash to fund future years' debt maturities.
Additional alternatives could be considered based upon the actual amount, if
any, of such excess cash.
Credit Lines
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").
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 December 31, 2002, there were no borrowings outstanding under the
$725 million U.S. Facility. The available capacity under the U.S. Facility as of
December 31, 2002, net of $25 million of outstanding letters of credit, was $700
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 December
31, 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. Devon has
historically elected a rate that is based upon LIBOR, plus a margin dictated by
Devon's debt rating. Borrowings under the Canadian Facility have also been made
under a rate based upon the Bankers' Acceptance rate, plus a margin dictated by
Devon's debt rating. Based upon its current debt rating, Devon can borrow under
the Credit Facilities at a rate of between 45 and 125 basis points above LIBOR
based upon usage and the tranche utilized, and 72.5 basis points above the
Bankers' Acceptance rate. The Credit Facilities also provide for an annual
facility fee of $1.4 million that is payable quarterly.
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 it can have a maturity of up to
365 days. Devon had no commercial paper debt outstanding at December 31, 2002.
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<PAGE>
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 December 31, 2002, C$109 million ($69 million
converted to U.S. dollars using the December 31, 2002 exchange rate) of letters
of credit were issued under the LOC Facility primarily for Canadian drilling
commitments.
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 December 31, 2002, $1.9 billion of the
balance had been 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 $1.4 billion from the sale of certain oil and gas properties, of
which $1.1 billion was used to pay down debt.
The remaining balance outstanding as of December 31, 2002 will mature as
follows:
<Table>
<Caption>
(IN MILLIONS)
<S> <C>
April 15, 2006.............................................. $ 335
October 15, 2006............................................ 800
------
$1,135
======
</Table>
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 December 31, 2002, the average interest
rate on this facility was 2.5%.
Devon's 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. In accordance with the agreements,
total funded debt excludes the debentures that are exchangeable into shares of
ChevronTexaco 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 December 31, 2002, Devon's ratio of total funded
debt to total capitalization, as defined in its credit agreements, was 55.0%.
Devon's access to funds from its Credit Facilities is not restricted under
any "material adverse condition" clauses. It is not uncommon for credit
agreements to include such clauses. These clauses can remove the obligation of
the banks to fund the credit line if any condition or event would reasonably be
expected to have a material and adverse effect on the borrower's financial
condition, operations, properties or prospects considered as a whole, the
borrower's ability to make timely debt payments, or the enforceability of
material terms of the credit agreement. While Devon's Credit Facilities and its
$3 billion term loan credit facility include covenants that require Devon to
report a condition or event having a material adverse effect on the company, the
obligation of the banks to fund the Credit Facilities is not conditioned on the
absence of a material adverse effect.
Long-Term 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
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<PAGE>
2002 to partially fund the early extinguishment of $175 million of 8.75% senior
subordinated notes due June 15, 2007. The notes were redeemed at 104.375% of
principal, or approximately $183 million.
Debt Ratings
Devon receives debt ratings from the major ratings agencies in the United
States. In determining Devon's debt rating, the agencies consider a number of
items including, but not limited to, debt levels, planned asset sales, near-term
and long-term production growth opportunities, capital allocation challenges,
liquidity, asset quality, cost structure, reserve mix, and commodity pricing
levels.
Devon's current debt ratings are BBB with a stable outlook by Standard &
Poor's, Baa2 with a negative outlook by Moody's and BBB with a stable outlook by
Fitch. There are no "rating triggers" in any of Devon's contractual obligations
that would accelerate scheduled maturities should Devon's debt rating fall below
a specified level. Certain of Devon's agreements related to its oil and natural
gas hedges do contain provisions that could require Devon to provide cash
collateral in situations where Devon's liability under the hedge is above a
certain dollar threshold and where Devon's debt rating is below investment grade
(BBB- or Baa3). However, Devon's liability under these agreements would only
exceed the threshold level in circumstances where the market prices for oil or
natural gas were rising. It is unlikely that Devon's debt rating would be
subjected to downgrades to non-investment grade levels during such a period of
rising oil and natural gas prices.
As summarized earlier in this section, Devon's cost of borrowing under its
Credit Facilities and its $3 billion term loan facility is predicated on its
corporate debt rating. Therefore, even though a ratings downgrade would not
accelerate scheduled maturities, it would adversely impact Devon's interest rate
on its variable rate debt. Under the terms of the Credit Facilities and the term
loan credit facility, a one-notch downgrade would increase Devon's fully drawn
borrowing rates by 25 basis points for each facility. The average borrowing
costs for the Credit Facilities would increase from LIBOR plus 95 basis points
to LIBOR plus 120 basis points and the borrowing costs for the $3 billion term
loan facility would increase from LIBOR plus 100 basis points to LIBOR plus 125
basis points. A ratings downgrade could also adversely impact Devon's ability to
economically access future debt markets.
As of January 31, 2003, Devon was not aware of any potential ratings
downgrades being contemplated by the rating agencies.
Contractual Obligations
A summary of Devon's contractual obligations as of December 31, 2002, is
provided in the following table.
<Table>
<Caption>
PAYMENTS DUE BY YEAR
-------------------------------------------------
AFTER
2003 2004 2005 2006 2007 2007 TOTAL
---- ---- ---- ----- ---- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term debt....................... $ -- 336 347 1,262 -- 5,725 7,670
Operating leases..................... 30 33 28 24 20 86 221
Drilling obligations................. 151 34 37 1 -- -- 223
Firm transportation agreements....... 97 83 61 52 45 221 559
---- --- --- ----- -- ----- -----
Total.............................. $278 486 473 1,339 65 6,032 8,673
==== === === ===== == ===== =====
</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 aid Devon in moving its gas
production to market.
The above table does not include $94 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
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<PAGE>
Devon's Canadian drilling commitments ($40 million of which are included in the
above table). The $7.7 billion of long-term debt shown in the table excludes
$113 million of discounts and a $5 million fair value adjustment, both of which
are included in the December 31, 2002, book balance of the debt.
Pension Obligations
Devon accounts for its defined benefit pension plans using SFAS No. 87,
Employer's Accounting for Pensions. Under SFAS 87, pension expense is
recognized on an accrual basis over employees' approximate service periods.
Pension expense calculated under SFAS 87 is generally independent of funding
decisions or requirements. Devon recognized expense for its defined benefit
pension plans of $16 million, $7 million, and $5 million in 2002, 2001 and 2000,
respectively. Devon estimates that its pension expense will approximate $30
million in 2003.
As compared to the "projected benefit obligation," Devon's qualified and
nonqualified defined benefit plans were underfunded by $179 million and $54
million at December 31, 2002 and 2001, respectively. The increase in the
underfunded amount during 2002 was primarily caused by additional underfunded
obligations assumed in the January 2002 Mitchell acquisition, losses on
investments and actuarial losses. A detailed reconciliation of the 2002 activity
is included in Note 10 to the accompanying consolidated financial statements. Of
the $179 million underfunded status at the end of 2002, $75 million is
attributable to various nonqualified defined benefit plans which have no plan
assets. However, certain trusts have been established to assist Devon in funding
the benefit obligations of such nonqualified plans. As of December 31, 2002,
these trusts had investments with a market value of $53 million. The value of
these trusts is included in noncurrent other assets in Devon's accompanying
consolidated balance sheets.
As compared to the "accumulated benefit obligation," Devon's qualified
defined benefit plans were underfunded by $82 million at December 31, 2002. The
accumulated benefit obligation differs from the projected benefit obligation in
that the former includes no assumption about future compensation levels. Devon's
current intentions are to fund this accumulated benefit obligation deficit over
the two-year period ending December 31, 2004. The actual amount of contributions
required during this period will depend on investment returns from the plan
assets and any changes in actuarial assumptions made during the same period.
The calculation of pension expense and pension liability requires the use
of a number of assumptions. Changes in these assumptions can result in different
expense and liability amounts, and future actual experience can differ from the
assumptions. Devon believes that the two most critical assumptions affecting
pension expense and liabilities are the expected long-term rate of return on
plan assets and the assumed discount rate.
Devon assumed that its plan assets would generate a long-term weighted
average rate of return of 8.27% at December 31, 2002 and 2001, and 8.5% at
December 31, 2000. Devon developed these expected long-term rate of return
assumptions by evaluating input from external consultants and economists as well
as long-term inflation assumptions. The expected long-term rate of return on
plan assets is based on a target allocation of investment types in such assets.
The target investment mix for Devon's plan assets are approximately 65% domestic
equities, 15% international equities, and 20% fixed income instruments.
Devon believes that its long-term asset allocation on average will
approximate the targeted allocation. Devon regularly reviews its actual asset
allocation and periodically rebalances the investments to the targeted
allocation when considered appropriate.
Pension expense increases as the expected rate of return on plan assets
decreases. A decrease in Devon's long-term rate of return assumption of 100
basis points (from 8.27% to 7.27%) would increase the expected 2003 pension
expense by approximately $3 million.
Devon discounted its future pension obligations using a weighted average
rate of 6.72% at December 31, 2002, compared to 7.10% at December 31, 2001, and
7.65% at December 31, 2000. The discount rate is determined at the end of each
year based on the rate at which obligations could be effectively settled. This
rate is based on high-quality bond yields, after allowing for call and default
risk.
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<PAGE>
Devon considers high quality corporate bond yield indices, such as Moody's Aa,
when selecting the discount rate.
The pension liability and future pension expense both increase as the
discount rate is reduced. Lowering the discount rate by 25 basis points (from
6.72% to 6.47%) would increase Devon's pension liability at December 31, 2002,
by approximately $14 million, and increase its estimated 2003 pension expense by
approximately $2 million.
At December 31, 2002, Devon had unrecognized actuarial losses of $152
million. These losses will be recognized as a component of pension expense in
future years. Devon estimates that approximately $10 million, $9 million and $8
million of the unrecognized actuarial losses will be included in pension expense
in 2003, 2004 and 2005, respectively. The $10 million estimated to be recognized
in 2003 is a component of the total estimated 2003 pension expense of $30
million referred to earlier in this discussion.
Future changes in plan asset returns, assumed discount rates and various
other factors related to the participants in Devon's defined benefit pension
plans will impact future pension expense and liabilities. Devon cannot predict
with certainty what these factors will be in the future.
CRITICAL ACCOUNTING POLICIES
FULL COST CEILING CALCULATIONS
Devon follows the full cost method of accounting for its oil and gas
properties. The full cost method subjects companies to quarterly calculations of
a "ceiling", or limitation on the amount of properties that can be capitalized
on the balance sheet. If Devon's capitalized costs are in excess of the
calculated ceiling, the excess must be written off as an expense. The ceiling
limitation is imposed separately for each country in which Devon has oil and gas
properties.
Devon's discounted present value of its proved oil, natural gas and NGL
reserves is a major component of the ceiling calculation, and represents the
component that requires the most subjective judgments. Estimates of reserves are
forecasts based on engineering data, projected future rates of production and
the timing of future expenditures. The process of estimating oil, natural gas
and NGL reserves requires substantial judgment, resulting in imprecise
determinations, particularly for new discoveries. Different reserve engineers
may make different estimates of reserve quantities based on the same data.
Certain of Devon's reserve estimates are prepared by outside consultants, while
other reserve estimates are prepared by Devon's engineers. See Note 14 of the
accompanying consolidated financial statements.
The passage of time provides more qualitative information regarding
estimates of reserves, and revisions are made to prior estimates to reflect
updated information. In the past four years, Devon's annual revisions to its
reserve estimates have averaged approximately 3% of the previous year's
estimate. However, there can be no assurance that more significant revisions
will not be necessary in the future. If future significant revisions are
necessary that reduce previously estimated reserve quantities, it could result
in a full cost property writedown. In addition to the impact of the estimates of
proved reserves on the calculation of the ceiling, estimates of proved reserves
are also a significant component of the calculation of DD&A.
While the quantities of proved reserves require substantial judgment, the
associated prices of oil, natural gas and NGL reserves, and the applicable
discount rate, that are used to calculate the discounted present value of the
reserves do not require judgment. The ceiling calculation dictates that prices
and costs in effect as of the last day of the period are generally held constant
indefinitely. Therefore, the future net revenues associated with the estimated
proved reserves are not based on Devon's assessment of future prices or costs,
but rather are based on such prices and costs in effect as of the end of each
quarter when the ceiling calculation is performed. In calculating the ceiling,
Devon does not adjust the end-of-period price by the effect of cash flow hedges
in place.
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<PAGE>
The ceiling calculation also dictates that a 10% discount factor is to be
used to calculate the present value of net cash flows.
Because the ceiling calculation dictates that prices in effect as of the
last day of the applicable quarter are held constant indefinitely, and requires
a 10% discount factor, 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. 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 end of June 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 MMBtu.
Devon also recorded writedowns to its domestic and Canadian oil and gas
properties as of December 31, 2001. The domestic properties were reduced by $449
million and the Canadian properties were reduced by $434 million. The year-end
2001 prices used to calculate the ceiling were based on a NYMEX oil price of
$19.84 per barrel, a Henry Hub gas price of $2.65 per MMBtu and an AECO gas
price of C$3.67 per MMBtu.
If oil or gas prices at the end of future quarters drop below these June
30, 2002 or December 31, 2001 prices, or if Devon reduces its estimates of
proved reserve quantities, further writedowns would likely occur.
FAIR VALUES OF DERIVATIVE INSTRUMENTS
The estimated fair values of Devon's derivative instruments are recorded on
Devon's consolidated balance sheets. Substantially all of Devon's derivative
instruments represent hedges of the price of future oil and natural gas
production. Therefore, while fair values of such hedging instruments must be
estimated as of the end of each reporting period, the changes in the fair values
are not included in Devon's consolidated results of operations. Instead, the
changes in fair value of hedging instruments are recorded directly to
stockholders' equity until the hedged oil or natural gas quantities are
produced.
The estimates of the fair values of Devon's hedging derivatives require
substantial judgment. Devon obtains forward price and volatility data for all
major oil and gas trading points in North America from independent third
parties. These forward prices are compared to the price parameters contained in
the hedge agreements, and the resulting estimated future cash inflows or
outflows over the lives of the hedges are discounted using Devon's current
borrowing rates under its revolving credit facilities. In addition, Devon
estimates the option value of price floors and price caps using the
Black-Scholes option pricing model. These pricing and discounting variables are
sensitive to market volatility as well as changes in forward prices, regional
price differentials and interest rates.
As stated earlier, substantially all of Devon's derivative instruments are
hedges of the price of future oil and natural gas production. Devon is not
involved in any speculative trading activities of derivatives.
BUSINESS COMBINATIONS
Devon has grown substantially during recent years through acquisitions of
other oil and natural gas companies. Most of these acquisitions have been
accounted for using the purchase method of accounting,
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<PAGE>
and recent accounting pronouncements require that all future acquisitions will
be accounted for using the purchase method.
Under the purchase method, the acquiring company adds to its balance sheet
the estimated fair values of the acquired company's assets and liabilities. Any
excess of the purchase price over the fair values of the tangible and intangible
net assets acquired is recorded as goodwill. As of January 1, 2002, the
accounting for goodwill has changed. In prior years, goodwill was amortized over
its estimated useful life. As of 2002, goodwill is no longer amortized, but
instead is assessed for impairment at least annually.
There are various assumptions made by Devon in determining the fair values
of an acquired company's assets and liabilities. The most significant
assumptions, and the ones requiring the most judgment, involve the estimated
fair values of the oil and gas properties acquired. To determine the fair values
of these properties, Devon prepares estimates of oil, natural gas and NGL
reserves. These estimates are based on work performed by Devon's engineers and
that of outside consultants. The judgments associated with these estimated
reserves are described earlier in this section in connection with the full cost
ceiling calculation.
However, there are factors involved in estimating the fair values of
acquired oil, natural gas and NGL properties that require more judgment than
that involved in the full cost ceiling calculation. As stated above, the full
cost ceiling calculation applies current price and cost information to the
reserves to arrive at the ceiling amount. By contrast, the fair value of
reserves acquired in a business combination must be based on Devon's estimates
of future oil, natural gas and NGL prices. Devon's estimates of future prices
are based on its own analysis of pricing trends. These estimates are based on
current data obtained with regard to regional and worldwide supply and demand
dynamics such as economic growth forecasts. They are also based on industry data
regarding natural gas storage availability, drilling rig activity, changes in
delivery capacity, trends in regional pricing differentials and other
fundamental analysis. Future price forecasts from independent third parties are
noted when Devon makes its pricing estimates.
Devon's estimates of future prices are applied to the estimated reserve
quantities acquired to arrive at estimates of future net revenues. For estimated
proved reserves, the future net revenues are then discounted using a rate
determined appropriate at the time of the business combination based upon
Devon's cost of capital.
Devon also applies these same general principles in arriving at the fair
value of unproved reserves acquired in a business combination. These unproved
reserves are generally classified as either probable or possible reserves.
Because of their very nature, probable and possible reserve estimates are more
imprecise than those of proved reserves. To compensate for the inherent risk of
estimating and valuing unproved reserves, the discounted future net revenues of
probable and possible reserves are reduced by what Devon considers to be an
appropriate risk-weighting factor in each particular instance. It is common for
the discounted future net revenues of probable and possible reserves to be
reduced by factors ranging from 30% to 80% to arrive at what Devon considers to
be the appropriate fair values.
Generally, in Devon's business combinations, the determination of the fair
values of oil and gas properties requires much more judgment than the fair
values of other assets and liabilities. The acquired companies commonly have
long-term debt that Devon assumes in the acquisition, and this debt must be
recorded at the estimated fair value as if Devon had issued such debt. However,
significant judgment on Devon's behalf is usually not required in these
situations due to the existence of comparable market values of debt issued by
Devon's peer companies.
Prior to the 2002 Mitchell acquisition, Devon's mergers and acquisitions
have involved other entities whose operations were predominantly in the area of
exploration, development and production activities related to oil and gas
properties. However, in addition to exploration, development and production
activities, Mitchell's business also included substantial marketing and
midstream activities. Therefore, a portion of the Mitchell purchase price was
allocated to the fair value of Mitchell's marketing and midstream facilities and
equipment, which consisted primarily of natural gas processing plants and
natural gas pipeline systems.
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<PAGE>
Because the Mitchell marketing and midstream assets primarily served gas
producing properties that were also acquired by Devon from Mitchell, certain of
the assumptions regarding future operations of the gas producing properties were
also integral to the value of the marketing and midstream assets. For example,
future quantities of natural gas estimated to be processed by natural gas
processing plants were based on the same estimates used to value the proved and
unproved gas producing properties. Future expected prices for marketing and
midstream product sales were also based on price cases consistent with those
used to value the oil and gas producing assets acquired from Mitchell. Based on
historical costs and known trends and commitments, Devon also estimated future
operating and capital costs of the marketing and midstream assets to arrive at
estimated future cash flows. These cash flows were discounted at rates
consistent with those used to discount future net cash flows from oil and gas
producing assets to arrive at Devon's estimated fair value of the marketing and
midstream facilities and equipment.
VALUATION OF GOODWILL
Effective January 1, 2002, Devon adopted the remaining provisions of SFAS
No. 142, Goodwill and Other Intangible Assets. 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. This requires Devon to estimate
the fair values of its own assets and liabilities in a manner similar to the
process described above for a business combination. Therefore, considerable
judgment similar to that described above in connection with estimating the fair
value of an acquired company in a business combination is also required to
assess goodwill for impairment on an annual basis.
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 the discounted present 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."
The asset retirement cost equal to the discounted 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 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 previously estimated costs of dismantlement, removal, site
reclamation, and other similar activities in the total costs that are subject to
depreciation, depletion, and amortization. However, Devon did not record a
separate asset or liability for such amounts. Upon adoption of SFAS No. 143 on
January 1, 2003, Devon expects to record a cumulative-effect-type adjustment for
an increase to net earnings of between $10 million and $30 million, net of
deferred tax expense of between $5 million and $15 million. Additionally, Devon
expects to establish an asset retirement obligation of between $425 million and
$475 million, an increase to property and equipment of between $375 million and
$425 million and a decrease in accumulated DD&A of between $65 million and $95
million.
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
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<PAGE>
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 early adopted the provisions related to SFAS No. 145
during the fourth quarter 2002. With the adoption of SFAS No. 145, a loss of $6
million resulting from extinguishment of debt in 1999 was reclassified from
extraordinary loss to interest expense, and 1999's current income tax expense
was reduced by the $2 million tax benefit related to the loss from early
extinguishment.
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.
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.
In November 2002, the FASB issued Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others, an interpretation of FASB Statements No.
5, 57 and 107 and a rescission of FASB Interpretation No. 34. This
Interpretation elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under guarantees
issued. The Interpretation also clarifies that a guarantor is required to
recognize, at inception of a guarantee, a liability for the fair value of the
obligation undertaken. The initial recognition and measurement provisions of the
Interpretation are applicable to guarantees issued or modified after December
31, 2002 and are not expected to have a material effect on Devon's financial
statements. The disclosure requirements are effective for financial statements
of interim and annual periods ending after December 31, 2002 and are included in
the notes to the accompanying consolidated financial statements.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment of FASB Statement No.
123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based
Compensation, to provide alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee
compensation. In addition, this Statement amends the disclosure requirements of
Statement No. 123 to require prominent disclosures in both annual and interim
financial statements. Certain of the disclosure modifications are required for
fiscal years ending after December 15, 2002 and are included in the notes to the
accompanying consolidated financial statements.
In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51. Interpretation No. 46 requires a company to consolidate a variable
interest entity if the company has a variable interest (or combination of
variable interests) that will absorb a majority of the entity's expected losses
if they occur, receive a majority of the entity's expected residual returns if
they occur, or both. A direct or indirect ability to make decisions that
significantly affect the results of the activities of a variable interest entity
is a strong indication that a company has one or both of the characteristics
that would require consolidation of the variable interest entity. Interpretation
No. 46 also requires additional disclosures regarding variable interest
entities. The new interpretation is effective immediately for variable interest
entities created after January 31, 2003, and is effective in the first interim
or annual period beginning after June 15, 2003, for variable interest entities
in which a company holds a variable interest that it acquired before February 1,
2003. Devon owns no
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interests in variable interest entities, and therefore this new interpretation
will not affect Devon's consolidated financial statements.
2003 ESTIMATES
The forward-looking statements provided in this discussion are based on
management's examination of historical operating trends, the information which
was used to prepare the December 31, 2002 reserve reports of independent
petroleum engineers and other data in Devon's possession or available from third
parties. Devon cautions that its future oil, natural gas and NGL production,
revenues and expenses are subject to all of the risks and uncertainties normally
incident to the exploration for and development, production and sale of oil, gas
and NGLs. These risks include, but are not limited to, price volatility,
inflation or lack of availability of goods and services, environmental risks,
drilling risks, regulatory changes, the uncertainty inherent in estimating
future oil and gas production or reserves, and other risks as outlined below.
Additionally, Devon cautions that its future marketing and midstream revenues
and expenses are subject to all of the risks and uncertainties normally incident
to the marketing and midstream business. These risks include, but are not
limited to, price volatility, environmental risks, regulatory changes, the
uncertainty inherent in estimating future processing volumes and pipeline
throughput, cost of goods and services and other risks as outlined below. Also,
the financial results of Devon's foreign operations are subject to currency
exchange rate risks. Additional risks are discussed below in the context of line
items most affected by such risks.
SPECIFIC ASSUMPTIONS AND RISKS RELATED TO PRICE AND PRODUCTION ESTIMATES
Prices for oil, natural gas and NGLs are determined primarily by prevailing
market conditions. Market conditions for these products are influenced by
regional and worldwide economic conditions, weather and other local market
conditions. These factors are beyond Devon's control and are difficult to
predict. In addition to volatility in general, Devon's oil, gas and NGL prices
may vary considerably due to differences between regional markets,
transportation availability and costs and demand for the various products
derived from oil, natural gas and NGLs. Substantially all of Devon's revenues
are attributable to sales, processing and transportation of these three
commodities. Consequently, Devon's financial results and resources are highly
influenced by price volatility.
Estimates for Devon's future production of oil, natural gas and NGLs are
based on the assumption that market demand and prices for oil, gas and NGLs will
continue at levels that allow for profitable production of these products. There
can be no assurance of such stability. Also, Devon's international production of
oil, natural gas and NGLs is governed by payout agreements with the governments
of the countries in which Devon operates. If the payout under these agreements
is attained earlier than projected, Devon's net production and proved reserves
in such areas could be reduced.
Estimates for Devon's future processing and transport of oil, natural gas
and NGLs are based on the assumption that market demand and prices for oil, gas
and NGLs will continue at levels that allow for profitable processing and
transport of these products. There can be no assurance of such stability.
The production, transportation, processing and marketing of oil, natural
gas and NGLs are complex processes which are subject to disruption due to
transportation and processing availability, mechanical failure, human error,
meteorological events including, but not limited to, hurricanes, and numerous
other factors. The following forward-looking statements were prepared assuming
demand, curtailment, producibility and general market conditions for Devon's
oil, natural gas and NGLs during 2003 will be substantially similar to those of
2002, unless otherwise noted.
Given the general limitations expressed herein, following are Devon's
forward-looking statements for 2003. Unless otherwise noted, all of the
following dollar amounts are expressed in U.S. dollars. Amounts related to
Canadian operations have been converted to U.S. dollars using an exchange rate
of $0.65 U.S. dollar to $1.00 Canadian dollar. The actual 2003 exchange rate may
vary materially from this estimated rate. Such variations could have a material
effect on the following estimates.
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Though Devon has completed several major property acquisitions and
dispositions 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 or dispositions, if any. As discussed in Note 16 to
the accompanying consolidated financial statements, on February 24, 2003, Devon
announced its intent to merge with Ocean Energy, Inc. ("Ocean"). The following
forward-looking estimates do not include the additional revenues and expenses
that Devon will report in 2003 if this merger is consummated.
GEOGRAPHIC REPORTING AREAS FOR 2003
The following estimates of production, average price differentials and
capital expenditures are provided
separately for each of the following geographic areas:
- the United States;
- Canada; and
- International, which encompasses all oil and gas properties that lie
outside of the United States and Canada.
YEAR 2003 POTENTIAL OPERATING ITEMS
OIL, GAS AND NGL PRODUCTION
Set forth in the following paragraphs are individual estimates of Devon's
oil, gas and NGL production for 2003. On a combined basis, Devon estimates its
2003 oil, gas and NGL production will total between 178.1 and 186.9 MMBoe. Of
this total, approximately 92% is estimated to be produced from reserves
classified as "proved" at December 31, 2002.
OIL PRODUCTION
Devon expects its oil production in 2003 to total between 35.4 and 37.2
MMBbls. Of this total, approximately 92% is estimated to be produced from
reserves classified as "proved" at December 31, 2002. The expected ranges of
production by area are as follows:
<Table>
<Caption>
(MMBbls)
------------
<S> <C>
United States............................................... 19.1 to 20.1
Canada...................................................... 13.5 to 14.2
International............................................... 2.8 to 2.9
</Table>
OIL PRICES -- FLOATING
Devon's 2003 average prices for each of its areas are expected to differ
from the NYMEX price as set forth in the following table. The NYMEX price is the
monthly average of settled prices on each trading day for West Texas
Intermediate Crude oil delivered at Cushing, Oklahoma.
<Table>
<Caption>
EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE
----------------------------
<S> <C>
United States............................................... ($3.00) to ($2.00)
Canada...................................................... ($6.25) to ($4.25)
International............................................... ($2.80) to ($1.80)
</Table>
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its 2003 oil production that otherwise is subject
to floating prices. The floor and ceiling prices related to domestic and
Canadian oil production are based on the NYMEX price. 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
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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.
To simplify presentation, Devon's costless collars as of January 31, 2003,
have been aggregated in the following table according to similar floor prices
and similar ceiling prices. The floor and ceiling prices shown are weighted
averages of the various collars in each aggregated group.
<Table>
<Caption>
WEIGHTED AVERAGE
-----------------
Floor Ceiling
Price Price MONTHS OF
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) Bbls/Day Per Bbl Per Bbl PRODUCTION
- ------------------------------------------- -------- ------- ------- ----------
<S> <C> <C> <C> <C>
United States
($20.00 - $22.75/$27.05 - $28.65)............. 18,000 $21.65 $27.91 Jan - Dec
United States
($23.25 - $23.50/$28.25 - $30.00)............. 8,000 $23.38 $29.12 Jan - Dec
United States
($23.50 - $23.50/$28.25 - $30.75)............. 6,000 $23.50 $29.31 Jul - Dec
Canada ($20.00 - $21.00/$26.60 - $28.15)........ 5,000 $20.40 $27.37 Jan - Dec
Canada ($22.00 - $22.75/$27.00 - $28.40)........ 13,000 $22.29 $27.52 Jan - Dec
Canada ($23.25 - $23.50/$28.35 - $29.25)........ 5,000 $23.30 $28.79 Jan - Dec
Canada ($23.50 - $23.50/$28.80 - $29.75)........ 3,000 $23.50 $29.18 Jul - Dec
</Table>
GAS PRODUCTION
Devon expects its 2003 gas production to total between 731 Bcf and 767 Bcf.
Of this total, approximately 91% is estimated to be produced from reserves
classified as "proved" at December 31, 2002. The expected ranges of production
by area are as follows:
<Table>
<Caption>
(Bcf)
-----
<S> <C>
United States............................................... 472 to 495
Canada...................................................... 259 to 272
</Table>
GAS PRICES -- FIXED
Through various price swaps and fixed-price physical delivery contracts,
Devon has fixed the price it will receive in 2003 on a portion of its natural
gas production. The following table includes information on this fixed-price
production by area. 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.
<Table>
<Caption>
Mcf/DAY Price/Mcf MONTHS OF PRODUCTION
------- --------- --------------------
<S> <C> <C> <C>
United States.................................. 97,148 $3.23 Jan - Dec
Canada......................................... 43,578 $2.30 Jan - Jun
Canada......................................... 43,578 $2.29 Jul - Dec
</Table>
GAS PRICES -- FLOATING
For the natural gas production for which prices have not been fixed,
Devon's 2003 average prices for each of its areas are expected to differ from
the NYMEX price as set forth in the following table. The NYMEX price is
represented by the first-of-month South Louisiana Henry Hub price index as
published monthly in Inside FERC.
<Table>
<Caption>
EXPECTED RANGE OF GAS PRICES
LESS THAN NYMEX PRICE
----------------------------
<S> <C>
United States............................................... ($0.80) to ($0.30)
Canada...................................................... ($0.90) to ($0.40)
</Table>
Devon has also entered into costless price collars that set a floor and
ceiling price for a portion of its 2003 natural gas production that otherwise is
subject to floating prices. If the applicable monthly price
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<PAGE>
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.
To simplify presentation, Devon's costless collars as of January 31, 2003
have been aggregated in the following table according to similar floor prices
and similar ceiling 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 2003 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.
<Table>
<Caption>
WEIGHTED
AVERAGE
---------------------
AREA (RANGE OF FLOOR PRICES/CEILING MMBtu/DAY FLOOR CEILING
PRICES) --------- PRICE PRICE MONTHS
- ----------------------------------- PER PER OF
MMBtu MMBtu PRODUCTION
--------- --------- ----------
<S> <C> <C> <C> <C>
United States
($3.28 - $3.28/$6.23 - $6.53)........... 40,000 $3.28 $6.38 Jan - Dec
United States
($3.28 - $3.28/$5.53 - $5.93)........... 55,000 $3.28 $5.74 Jan - Dec
United States
($3.25 - $3.28/$4.65 - $4.93)........... 70,000 $3.27 $4.80 Jan - Dec
United States
($3.00 - $3.28/$4.05 - $4.20)........... 130,000 $3.12 $4.11 Jan - Dec
United States
($3.28 - $3.45/$4.20 - $4.49)........... 110,000 $3.35 $4.37 Jan - Dec
United States
($3.44 - $3.44/$6.69 - $6.69)........... 5,000 $3.44 $6.69 Apr - Sep
Canada ($3.28 - $3.39/$6.85 - $7.13)...... 20,000 $3.34 $6.99 Jan - Dec
Canada ($3.38 - $3.57/$6.10 - $6.89)...... 80,000 $3.49 $6.52 Jan - Dec
Canada ($3.45 - $3.52/$4.27 - $4.89)...... 90,000 $3.48 $4.34 Jan - Dec
Canada ($3.66 - $3.67/$7.24 - $7.68)...... 30,000 $3.66 $7.44 Apr - Oct
Canada ($3.53 - $3.54/$5.27 - $5.96)...... 40,000 $3.54 $5.60 Jan - Dec
</Table>
NGL PRODUCTION
Devon expects its 2003 production of NGLs to total between 20.9 MMBbls and
21.9 MMBbls. Of this total, 96% is estimated to be produced from reserves
classified as "proved" at December 31, 2002. The expected ranges of production
by area are as follows:
<Table>
<Caption>
(MMBBLS)
------------
<S> <C>
United States............................................... 16.6 to 17.4
Canada...................................................... 4.3 to 4.5
</Table>
MARKETING AND MIDSTREAM REVENUES AND EXPENSES
Devon's marketing and midstream revenues and expenses are derived primarily
from its natural gas processing plants and natural gas transport pipelines.
These revenues and expenses vary in response to several factors. The factors
include, but are not limited to, changes in production from wells connected to
the pipelines and related processing plants, changes in the absolute and
relative prices of natural gas and NGLs, provisions of the agreements, and the
amount of repair and workover activity required to maintain anticipated
processing levels.
These factors, coupled with uncertainty of future natural gas and NGL
prices, increase the uncertainty inherent in estimating future marketing and
midstream revenues and expenses. Given these
54
<PAGE>
uncertainties, Devon estimates that 2003 marketing and midstream revenues will
be between $1.18 billion and $1.25 billion and marketing and midstream expenses
will be between $961 million and $1.02 billion.
PRODUCTION AND OPERATING EXPENSES
Devon's production and operating expenses include lease operating expenses,
transportation costs and production taxes. These expenses vary in response to
several factors. Among the most significant of these factors are additions to or
deletions from Devon's property base, changes in production tax rates, changes
in the general price level of services and materials that are used in the
operation of the properties and the amount of repair and workover activity
required. Oil, natural gas and NGL prices also have an effect on lease operating
expenses and impact the economic feasibility of planned workover projects.
Given these uncertainties, Devon estimates that 2003 lease operating
expenses will be between $611 million and $649 million, transportation costs
will be between $141 million and $150 million, and production taxes will be
between 3.7% and 4.2% of consolidated oil, natural gas and NGL revenues,
excluding revenues related to hedges upon which production taxes are not
incurred.
DEPRECIATION, DEPLETION AND AMORTIZATION ("DD&A")
The 2003 oil and gas property DD&A rate will depend on various factors.
Most notable among such factors are the amount of proved reserves that will be
added from drilling or acquisition efforts in 2003 compared to the costs
incurred for such efforts, and the revisions to Devon's year-end 2002 reserve
estimates that, based on prior experience, are likely to be made during 2003.
Based on these uncertainties, oil and gas property related DD&A expense for
2003 is expected to be between $1.1 billion and $1.2 billion. Additionally,
Devon expects its DD&A expense related to non-oil and gas property fixed assets
to total between $124 million and $132 million. This range includes $78 million
to $83 million related to marketing and midstream assets. Based on these DD&A
amounts and the production estimates set forth earlier, Devon expects its
consolidated DD&A rate will be between $6.82 per Boe and $7.22 per Boe.
ACCRETION OF ASSET RETIREMENT OBLIGATION
As discussed in the previous section titled "Impact of Recently Issued
Accounting Standards Not Yet Adopted", Devon adopted 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. 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 the discounted present 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." Because the asset retirement
obligation is a discounted value, accretion will be recognized as the estimated
date for settling the obligation draws closer.
As a result of the requirements of SFAS No. 143, Devon expects its 2003
accretion of its asset retirement obligation related to the adoption of SFAS 143
to be between $25 million and $35 million.
GENERAL AND ADMINISTRATIVE EXPENSES ("G&A")
Devon's G&A includes the costs of many different goods and services used in
support of its business. These goods and services are subject to general price
level increases or decreases. In addition, Devon's G&A varies with its level of
activity and the related staffing needs as well as with the amount of
professional services required during any given period. Should Devon's needs or
the prices of the required goods and services differ significantly from current
expectations, actual G&A could vary materially from
55
<PAGE>
the estimate. Given these limitations, consolidated G&A in 2003 is expected to
be between $215 million and $229 million.
INTEREST EXPENSE
Future interest rates, debt outstanding and oil, natural gas and NGL prices
have a significant effect on Devon's interest expense. Devon can only marginally
influence the prices it will receive in 2003 from sales of oil, natural gas and
NGLs and the resulting cash flow. These factors increase the margin of error
inherent in estimating future interest expense. Other factors which affect
interest expense, such as the amount and timing of capital expenditures, are
within Devon's control.
Assuming no changes in fixed-rate debt balances during 2003, Devon's
average balance of fixed-rate debt during 2003 will be $6.5 billion. The
interest expense in 2003 related to this fixed-rate debt, including net
accretion of related discounts, will be approximately $472 million. This
fixed-rate debt removes the uncertainty of future interest rates from some, but
not all, of Devon's long-term debt. Devon's floating rate debt is discussed in
the following paragraphs.
As of January 31, 2003, Devon had $1.1 billion outstanding under its
original $3.0 billion amortizing senior unsecured term loan credit facility.
This credit facility, which was entered into in October 2001, has a term of five
years. This credit facility is non-revolving.
The remaining balance outstanding as of January 31, 2003 will mature as
follows:
<Table>
<Caption>
(IN MILLIONS)
<S> <C>
April 15, 2006.............................................. $ 335
October 15, 2006............................................ 800
------
$1,135
======
</Table>
This $3 billion facility includes various rate options which can be elected
by Devon, including a rate based on LIBOR plus a margin. The margin is based on
Devon's debt rating. Based on Devon's current debt rating, the margin is 100
basis points. As of January 31, 2003, the average interest rate on this facility
was 2.3%.
From time to time, Devon borrows under its $1 billion credit facilities.
Borrowings under the U.S. facility, currently set at $725 million, may be
borrowed at various rate options including LIBOR plus a margin with interest
periods of up to six months. Borrowings under the Canadian facility, currently
set at $275 million, may be made at various rate options including LIBOR plus a
margin with interest periods up to six months, or Bankers Acceptances plus a
margin with interest periods of 30 to 180 days. The current LIBOR margin ranges
from 45 to 125 basis points based upon usage and the tranche utilized, and the
current Bankers Acceptance margin is 72.5 basis points over the cost of funding.
There were no borrowings under these facilities at January 31, 2003.
Devon also borrows under a $150 million Canadian dollar letter of credit
facility which is primarily used to issue letters of credit in association with
Devon's Canadian drilling commitments. As of December 31, 2002, there were $109
million Canadian dollars of issued letters of credit under this facility. Devon
may also use this facility for general corporate purposes.
From time to time, Devon also borrows under its commercial paper facility.
Total borrowings under the $725 million U.S. facility and the commercial paper
program cannot exceed $725 million. There were no borrowings under the
commercial paper facility as of December 31, 2002. Commercial paper borrowing
costs are typically 20 to 50 basis points over LIBOR. Debt outstanding under
this program is generally borrowed for seven to 90 day periods, and may be
borrowed up to 365 days, at prevailing commercial paper market rates.
Devon has fixed the interest rate on $125 million Canadian dollars and $50
million U.S. dollars of its floating rate debt through swap agreements at
average rates of 6.4% and 5.9%, respectively. The Canadian
56
<PAGE>
dollar swap agreements mature at various dates through July 2007 and the U.S.
dollar swap agreement matures in May 2003.
Devon has also entered into an interest rate swap on its $125 million 8.05%
senior notes due in 2004 to swap a fixed interest rate for a variable interest
rate. The variable interest rate on this instrument is based on LIBOR plus a
margin of 336 basis points. The interest rate swap is accounted for as a fair
value hedge under SFAS 133.
Devon's interest expense totals have historically included payments of
facility and agency fees, amortization of debt issuance costs, the effect of the
interest rate swaps, and other miscellaneous items not related to the debt
balances outstanding. Devon expects between $10 million and $20 million of such
items to be included in its 2003 interest expense. Based on the information
related to interest expense set forth herein and assuming no material changes in
Devon's levels of indebtedness or prevailing interest rates, Devon expects its
2003 interest expense will be between $512 million and $522 million.
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 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. 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, and requires
a 10% discount factor, 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.
Because of the volatile nature of oil and gas prices, it is not possible to
predict whether Devon will incur a full cost writedown in future periods.
EFFECTS OF CHANGES IN FOREIGN CURRENCY RATES
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 during 2003 will increase or decrease the
Canadian dollar equivalent balance of this debt. 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. Because of the
variability of the exchange rate, it is not possible to estimate the effect
which will be recorded in 2003. However, based on the January 31, 2003,
Canadian-to-U.S. dollar exchange rate of $0.6540, for every $0.01 change in the
exchange rate, Devon will record an effect (either income or expense) of
approximately $9 million Canadian dollars. The resulting revenue or expense in
U.S. dollars will depend on the currency exchange rate in effect throughout the
year.
57
<PAGE>
OTHER REVENUES
Devon's other revenues in 2003 are expected to be between $23 million and
$26 million.
INCOME TAXES
Devon's financial income tax rate in 2003 will vary materially depending on
the actual amount of financial pre-tax earnings. The tax rate for 2003 will be
significantly affected by the proportional share of consolidated pre-tax
earnings generated by U.S., Canadian and International operations due to the
different tax rates of each country. There are certain tax deductions and
credits that will have a fixed impact on 2003's income tax expense regardless of
the level of pre-tax earnings that are produced. Given the uncertainty of its
pre-tax earnings amount, Devon estimates that its consolidated financial income
tax rate in 2003 will be between 20% and 40%. The current income tax rate is
expected to be between 0% and 10%. The deferred income tax rate is expected to
be between 20% and 30%. Significant changes in estimated capital expenditures,
production levels of oil, gas and NGLs, the prices of such products, marketing
and midstream revenues, or any of the various expense items could materially
alter the effect of the aforementioned tax deductions and credits on 2003's
financial income tax rates.
YEAR 2003 POTENTIAL CAPITAL SOURCES, USES AND LIQUIDITY
CAPITAL EXPENDITURES
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. As discussed in Note 16 to the accompanying consolidated financial
statements, on February 24, 2003, Devon announced its intention to merge with
Ocean. The following forward-looking estimates do not include the additional
capital expenditures that Devon will report in 2003 if this merger is
consummated.
Devon's capital expenditures budget is based on an expected range of future
oil, natural gas and NGL prices as well as the expected costs of the capital
additions. Should actual prices received differ materially from Devon's price
expectations for its future production, some projects may be accelerated or
deferred and, consequently, may increase or decrease total 2003 capital
expenditures. In addition, if the actual costs of the budgeted items vary
significantly from the anticipated amounts, actual capital expenditures could
vary materially from Devon's estimates.
Given the limitations discussed, Devon expects its 2003 capital
expenditures for drilling and development efforts, plus related facilities, to
total between $1.4 billion and $1.6 billion. These amounts include between $455
million and $525 million for drilling and facilities costs related to reserves
classified as proved as of year-end 2002. In addition, these amounts include
between $485 million and $555 million for other low risk/reward projects and
between $435 million and $510 million for new, higher risk/reward projects. Low
risk/reward projects include development drilling that does not offset currently
productive units and for which there is not a certainty of continued production
from a known productive formation. Higher risk/reward projects include
exploratory drilling to find and produce oil or gas in previously untested fault
blocks or new reservoirs.
The following table shows expected drilling and production facilities
expenditures by geographic area.
<Table>
<Caption>
UNITED STATES CANADA INTERNATIONAL TOTAL
------------- --------- ------------- -------------
($ IN MILLIONS)
<S> <C> <C> <C> <C>
Related to Proved Reserves........ $330-$370 $105-$125 $30-$ 40 $ 465-$ 535
Lower Risk/Reward Projects........ $335-$375 $150-$180 $ 0-$ 0 $ 485-$ 555
Higher Risk/Reward Projects....... $180-$210 $205-$235 $50-$ 65 $ 435-$ 510
--------- --------- -------- -------------
Total............................. $845-$955 $460-$540 $80-$105 $1,385-$1,600
========= ========= ======== =============
</Table>
58
<PAGE>
In addition to the above expenditures for drilling and development, Devon
expects to spend between $150 million to $170 million on its marketing and
midstream assets, which include its oil pipelines, gas processing plants,
treating facilities and gas pipelines. Devon also expects to capitalize between
$85 million and $95 million of G&A expenses in accordance with the full cost
method of accounting. Devon also expects to pay between $30 million and $40
million for plugging and abandonment charges, and to spend between $50 million
and $60 million for other non-oil and gas property fixed assets.
OTHER CASH USES
Devon's management expects the policy of paying a quarterly common stock
dividend to continue. With the current $0.05 per share quarterly dividend rate
and 157 million shares of common stock outstanding, 2003 dividends are expected
to approximate $31 million. Also, Devon has $150 million of 6.49% cumulative
preferred stock upon which it will pay $10 million of dividends in 2003.
CAPITAL RESOURCES AND LIQUIDITY
Devon's estimated 2003 cash uses, including its drilling and development
activities, are expected to be funded primarily through a combination of working
capital and operating cash flow. The amount of operating cash flow to be
generated during 2003 is uncertain due to the factors affecting revenues and
expenses as previously cited. However, based upon current oil and gas price
expectations for 2003, Devon anticipates that its operating cash flow will
exceed its planned capital expenditures and other cash requirements for the
year. Devon currently intends to accumulate any excess cash to fund future
years' debt maturities. Additional alternatives could be considered based upon
the actual amount, if any, of such excess cash. If significant acquisitions or
other unplanned capital requirements arise during the year, Devon could utilize
its existing credit facilities and/or seek to establish and utilize other
sources of financing. As of December 31, 2002, Devon had $975 million available
under its $1 billion credit facilities, net of $25 million of outstanding
letters of credit.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about Devon's potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in oil, gas and NGL prices, interest rates and
foreign currency exchange rates. The disclosures are not meant to be precise
indicators of expected future losses, but rather indicators of reasonably
possible losses. This forward-looking information provides indicators of how
Devon views and manages its ongoing market risk exposures. All of Devon's market
risk sensitive instruments were entered into for purposes other than speculative
trading.
COMMODITY PRICE RISK
Devon's major market risk exposure is in the pricing applicable to its oil,
gas and NGLs 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 and NGL production. Pricing for oil, gas and NGL 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
speculative trading purposes.
Devon's total hedged positions as of January 31, 2003 are set forth in the
following tables.
59
<PAGE>
PRICE SWAPS
Through various price swaps, Devon has fixed the price it will receive on a
portion of its natural gas production in 2003. These swaps will result in a
fixed price of $3.23 per Mcf on 97,148 Mcf per day of domestic production during
2003. Where necessary, the prices related to these swaps 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 2003 and 2004 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 oil or 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 various collars.
OIL PRODUCTION
<Table>
<Caption>
2003
-----------------------------------------
WEIGHTED AVERAGE
-----------------
Floor Ceiling
Price Price MONTHS OF
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) Bbls/DAY Per Bbl Per Bbl PRODUCTION
- ------------------------------------------- -------- ------- ------- ----------
<S> <C> <C> <C> <C>
United States
($20.00 - $22.75/$27.05 - $28.65)............ 18,000 $21.65 $27.91 Jan - Dec
United States
($23.25 - $23.50/$28.25 - $30.00)............ 8,000 $23.38 $29.12 Jan - Dec
United States
($23.50 - $23.50/$28.25 - $30.75)............ 6,000 $23.50 $29.31 Jul - Dec
Canada ($20.00 - $21.00/$26.60 - $28.15)....... 5,000 $20.40 $27.37 Jan - Dec
Canada ($22.00 - $22.75/$27.00 - $28.40)....... 13,000 $22.29 $27.52 Jan - Dec
Canada ($23.25 - $23.50/$28.35 - $29.25)....... 5,000 $23.30 $28.79 Jan - Dec
Canada ($23.50 - $23.50/$28.80 - $29.75)....... 3,000 $23.50 $29.18 Jul - Dec
</Table>
<Table>
<Caption>
2004
-----------------------------------------
WEIGHTED AVERAGE
-----------------
Floor Ceiling
Price Price MONTHS OF
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) Bbls/Day Per Bbl Per Bbl PRODUCTION
- ------------------------------------------- -------- ------- ------- ----------
<S> <C> <C> <C> <C>
United States
($20.00 - $20.00/$26.50 - $28.00)............ 2,000 $20.00 $27.25 Jan - Dec
Canada ($20.00 - $20.00/$26.50 - $27.00)....... 2,000 $20.00 $26.75 Jan - Dec
</Table>
60
<PAGE>
GAS PRODUCTION
<Table>
<Caption>
2003
----------------------------------------------
WEIGHTED AVERAGE
---------------------
Floor Ceiling
Price Per Price Per MONTHS OF
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) MMBtu/DAY MMBtu MMBtu PRODUCTION
- ------------------------------------------- --------- --------- --------- ----------
<S> <C> <C> <C> <C>
United States
($3.28 - $3.28/$6.23 - $6.53)........... 40,000 $ 3.28 $6.38 Jan - Dec
United States
($3.28 - $3.28/$5.53 - $5.93)........... 55,000 $ 3.28 $5.74 Jan - Dec
United States
($3.25 - $3.28/$4.65 - $4.93)........... 70,000 $ 3.27 $4.80 Jan - Dec
United States
($3.00 - $3.28/$4.05 - $4.20)........... 130,000 $ 3.12 $4.11 Jan - Dec
United States
($3.28 - $3.45/$4.20 - $4.49)........... 110,000 $ 3.35 $4.37 Jan - Dec
United States
($3.44 - $3.44/$6.69 - $6.69)........... 5,000 $ 3.44 $6.69 Apr - Sep
Canada ($3.28 - $3.39/$6.85 - $7.13)...... 20,000 $ 3.34 $6.99 Jan - Dec
Canada ($3.38 - $3.57/$6.10 - $6.89)...... 80,000 $ 3.49 $6.52 Jan - Dec
Canada ($3.45 - $3.52/$4.27 - $4.89)...... 90,000 $ 3.48 $4.34 Jan - Dec
Canada ($3.66 - $3.67/$7.24 - $7.68)...... 30,000 $ 3.66 $7.44 Apr - Oct
Canada ($3.53 - $3.54/$5.27 - $5.96)...... 40,000 $ 3.54 $5.60 Jan - Dec
</Table>
<Table>
<Caption>
2004
----------------------------------------------
WEIGHTED AVERAGE
---------------------
Floor Ceiling
Price Per Price Per MONTHS OF
AREA (RANGE OF FLOOR PRICES/CEILING PRICES) MMBtu/DAY MMBtu MMBtu PRODUCTION
- ------------------------------------------- --------- --------- --------- ----------
<S> <C> <C> <C> <C>
United States
($3.28 - $3.28/$5.74 - $5.81)........... 30,000 $3.28 $5.79 Jan - Dec
United States
($3.28 - $3.28/$6.48 - $6.48)........... 10,000 $3.28 $6.48 Jan - Dec
Canada ($3.65 - $3.65/$5.67 - $5.80)...... 20,000 $3.65 $5.73 Jan - Dec
Canada ($3.52 - $3.62/$6.55 - $6.70)...... 20,000 $3.57 $6.62 Jan - Dec
Canada ($3.53 - $3.56/$6.05 - $6.30)...... 20,000 $3.55 $6.18 Jan - Dec
Canada ($3.47 - $3.56/$7.42 - $7.70)...... 30,000 $3.50 $7.59 Jan - Dec
</Table>
Devon uses a sensitivity analysis technique to evaluate the hypothetical
effect that changes in the market value of oil and gas may have on the fair
value of its commodity hedging instruments. At January 31, 2003, a 10% increase
in the underlying commodities' prices would have reduced the fair value of
Devon's commodity hedging instruments by $135 million.
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.
Devon has fixed-price physical delivery contracts for the years 2003
through 2011 covering Canadian natural gas production ranging from 8 Bcf to 16
Bcf per year. From 2012 through 2016, Devon also has Canadian gas volumes
subject to fixed-price contracts, but the yearly volumes are less than 1 Bcf.
INTEREST RATE RISK
At December 31, 2002, Devon had long-term debt outstanding of $7.6 billion.
Of this amount, $6.5 billion, or 85%, bears interest at fixed rates averaging
7%. The remaining $1.1 billion of debt outstanding bears interest at floating
rates which averaged 2.5%.
The terms of Devon's various floating rate debt facilities (revolving
credit facilities, commercial paper and term loan credit facility) allow
interest rates to be fixed at Devon's option for periods of between seven to 180
days. A 10% increase in short-term interest rates on the floating-rate debt
outstanding as of
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<PAGE>
December 31, 2002 would equal approximately 25 basis points. Such an increase in
interest rates would increase Devon's 2003 interest expense by approximately $3
million assuming borrowed amounts remain outstanding for all of 2003.
Devon assumed certain interest rate swaps as a result of the Anderson
acquisition. Under these interest rate swaps, Devon has swapped a floating rate
for a fixed rate. Under such swaps, Devon will record a fixed rate of 6.3% on
$98 million of debt in 2003, 6.4% on $79 million of debt in 2004 through 2006
and 6.3% on $24 million of debt in 2007. The amount of gains or losses realized
from such swaps are included as increases or decreases to interest expense.
Devon uses a sensitivity analysis technique to evaluate the hypothetical
effect that changes in interest rates may have on the fair value of its interest
rate swap instruments. At January 31, 2003, a 10% increase in the underlying
interest rates would have increased the fair value of Devon's interest rate
swaps by $2 million.
The above sensitivity analysis for interest rate risk excludes accounts
receivable, accounts payable and accrued liabilities because of the short-term
maturity of such instruments.
FOREIGN CURRENCY RISK
Devon's net assets, net earnings and cash flows from its Canadian
subsidiaries are based on the U.S. dollar equivalent of such amounts measured in
the Canadian dollar functional currency. Assets and liabilities of the Canadian
subsidiaries are translated to U.S. dollars using the applicable exchange rate
as of the end of a reporting period. Revenues, expenses and cash flow are
translated using the average exchange rate during the reporting period.
As a result of the Anderson acquisition, Devon's Canadian subsidiary, Devon
Canada, assumed $400 million of fixed-rate long-term debt that is denominated in
U.S. dollars. Changes in the currency conversion rate between the Canadian and
U.S. dollars between the beginning and end of a reporting period increase or
decrease the expected amount of Canadian dollars required to repay the notes.
The amount of such increase or decrease is required to be included in
determining net earnings for the period in which the exchange rate changes. A
$0.03 decrease in the Canadian-to-U.S. dollar exchange rate would cause Devon to
record a charge of approximately $20 million in 2003. The $400 million becomes
due in March 2011. Until then, the gains or losses caused by the exchange rate
fluctuations have no effect on cash flow.
Devon assumed certain foreign currency exchange rate swaps in the Anderson
acquisition. A portion of Devon's Canadian gas sales are based on U.S. dollar
prices. Therefore, currency fluctuations between the Canadian and U.S. dollars
impacts the amount of Canadian dollars received by Devon's Canadian subsidiaries
for this gas production. These foreign currency exchange rate swaps mitigate the
effect of volatility in the Canadian-to-U.S. dollar exchange rate on Canadian
gas revenues. Under these swap agreements, in 2003, Devon will sell $12 million
at average Canadian-to-U.S. exchange rates of $0.676, and buy the same amount of
dollars at the floating exchange rate. The amount of gains or losses realized
from such swaps are included as increases or decreases to realized gas sales. At
the December 31, 2002 exchange rate, these swaps would result in a decrease to
gas sales during 2003 of approximately $1 million. A further $0.03 decrease in
the Canadian-to-U.S. dollar exchange rate would result in an additional decrease
to 2003 gas sales of approximately $1 million.
For purposes of the sensitivity analysis described above for changes in the
Canadian dollar exchange rate, a change in the rate of $0.03 was used as opposed
to a 10% change in the rate. During the last ten years, the Canadian-to-U.S.
dollar exchange rate has fluctuated an average of approximately 4% per year, and
no year's fluctuation was greater than 7%. The $0.03 change used in the above
analysis represents an approximate 4% change in the year-end 2002 rate.
62
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND CONSOLIDATED
FINANCIAL STATEMENT SCHEDULES
<Table>
<Caption>
PAGE
----
<S> <C>
Independent Auditors' Report................................ 64
Consolidated Financial Statements:
Consolidated Balance Sheets
December 31, 2002, 2001, and 2000...................... 65
Consolidated Statements of Operations
Years Ended December 31, 2002, 2001, and 2000.......... 66
Consolidated Statements of Stockholders' Equity
Years Ended December 31, 2002, 2001, and 2000.......... 68
Consolidated Statements of Cash Flows
Years Ended December 31, 2002, 2001, and 2000.......... 69
Notes to Consolidated Financial Statements
December 31, 2002, 2001, and 2000...................... 70
</Table>
All financial statement schedules are omitted as they are inapplicable or
the required information has been included in the consolidated financial
statements or notes thereto.
63
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Devon Energy Corporation:
We have audited the accompanying consolidated balance sheets of Devon
Energy Corporation and subsidiaries (the Company) as of December 31, 2002, 2001
and 2000, and the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the years then ended. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Devon Energy
Corporation and subsidiaries as of December 31, 2002, 2001 and 2000, and the
results of their operations and their cash flows for each of the years then
ended, in conformity with accounting principles generally accepted in the United
States of America.
As described in Note 1 to the consolidated financial statements, as of
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activities; and, effective July 1, 2001, adopted the
provisions of Statement of Financial Accounting Standards ("SFAS") No. 141,
Business Combinations, and certain provisions of SFAS No. 142, Goodwill and
Other Intangible Assets; and effective January 1, 2002, adopted the remaining
provisions of SFAS No. 142.
KPMG LLP
Oklahoma City, Oklahoma
February 4, 2003
64
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
DECEMBER 31,
------------------------
2002 2001 2000
------- ------ -----
(IN MILLIONS, EXCEPT
SHARE DATA)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 292 183 194
Accounts receivable....................................... 639 489 562
Inventories............................................... 26 20 23
Deferred income taxes..................................... -- -- 9
Fair value of financial instruments....................... 4 195 --
Income taxes receivable................................... 56 68 --
Assets of discontinued operations......................... 7 354 --
Investments and other current assets...................... 40 45 40
------- ------ -----
Total current assets.................................... 1,064 1,354 828
------- ------ -----
Property and equipment, at cost, based on the full cost
method of accounting for oil and gas properties ($2,289,
$1,929 and $314 excluded from amortization in 2002, 2001
and 2000, respectively)................................... 18,786 14,899 9,091
Less accumulated depreciation, depletion and
amortization............................................ 7,934 6,137 4,429
------- ------ -----
10,852 8,762 4,662
Investment in ChevronTexaco Corporation common stock, at
fair value................................................ 472 636 599
Fair value of financial instruments......................... 1 31 --
Goodwill.................................................... 3,555 2,206 289
Assets of discontinued operations........................... -- -- 361
Other assets................................................ 281 195 121
------- ------ -----
Total assets.............................................. $16,225 13,184 6,860
======= ====== =====
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade................................................... $ 376 470 273
Revenues and royalties due to others.................... 261 124 115
Income taxes payable...................................... 9 16 64
Accrued interest payable.................................. 119 102 23
Merger related expenses payable........................... 12 7 52
Fair value of financial instruments....................... 151 15 --
Liabilities of discontinued operations.................... -- 56 --
Deferred income taxes..................................... -- 57 --
Accrued expenses.......................................... 114 72 50
------- ------ -----
Total current liabilities............................... 1,042 919 577
------- ------ -----
Other liabilities........................................... 323 172 158
Debentures exchangeable into shares of ChevronTexaco
Corporation common stock.................................. 662 649 760
Other long-term debt........................................ 6,900 5,940 1,289
Deferred revenue............................................ -- 51 114
Fair value of financial instruments......................... 18 45 --
Liabilities of discontinued operations...................... -- -- 51
Deferred income taxes....................................... 2,627 2,149 634
Stockholders' equity:
Preferred stock of $1.00 par value ($100 liquidation
value) Authorized 4,500,000 shares; issued 1,500,000 in
2002, 2001 and 2000..................................... 1 1 1
Common stock of $.10 par value Authorized 400,000,000
shares; issued 160,461,000 in 2002, 129,886,000 in 2001
and 128,638,000 in 2000................................. 16 13 13
Additional paid-in capital................................ 5,178 3,610 3,564
Accumulated deficit....................................... (84) (147) (215)
Accumulated other comprehensive loss...................... (267) (28) (85)
Unamortized restricted stock awards....................... (3) -- (1)
Treasury stock, at cost: 3,704,000 shares in 2002 and
3,754,000 shares in 2001................................ (188) (190) --
------- ------ -----
Total stockholders' equity.............................. 4,653 3,259 3,277
------- ------ -----
Commitments and contingencies (Notes 11 and 12)
Total liabilities and stockholders' equity.................. $16,225 13,184 6,860
======= ====== =====
</Table>
See accompanying notes to consolidated financial statements.
65
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
(IN MILLIONS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C> <C>
Revenues:
Oil sales................................................. $ 909 784 906
Gas sales................................................. 2,133 1,878 1,474
NGL sales................................................. 275 131 154
Marketing and midstream revenues.......................... 999 71 53
------ ----- -----
Total revenues.................................... 4,316 2,864 2,587
------ ----- -----
Operating Costs and Expenses:
Lease operating expenses.................................. 621 467 388
Transportation costs...................................... 154 83 53
Production taxes.......................................... 111 116 103
Marketing and midstream operating costs and expenses...... 808 47 28
Depreciation, depletion and amortization of property and
equipment.............................................. 1,211 831 662
Amortization of goodwill.................................. -- 34 41
General and administrative expenses....................... 219 114 96
Expenses related to mergers............................... -- 1 60
Reduction of carrying value of oil and gas properties..... 651 979 --
------ ----- -----
Total operating costs and expenses................ 3,775 2,672 1,431
------ ----- -----
Earnings from operations.................................... 541 192 1,156
Other Income (Expenses):
Interest expense.......................................... (533) (220) (155)
Effects of changes in foreign currency exchange rates..... 1 (11) (3)
Change in fair value of financial instruments............. 28 (2) --
Impairment of ChevronTexaco Corporation common stock...... (205) -- --
Other income.............................................. 34 69 40
------ ----- -----
Net other expenses................................ (675) (164) (118)
------ ----- -----
Earnings (loss) from continuing operations before income
taxes and cumulative effect of change in accounting
principle................................................. (134) 28 1,038
Income Tax Expense (Benefit):
Current................................................... 23 48 120
Deferred.................................................. (216) (43) 257
------ ----- -----
Total income tax expense (benefit)................ (193) 5 377
------ ----- -----
Earnings from continuing operations before cumulative effect
of change in accounting principle......................... 59 23 661
Discontinued Operations:
Results of discontinued operations before income taxes
(including net gain on disposal of $31 million in
2002).................................................. 54 56 104
Income tax expense........................................ 9 25 35
------ ----- -----
Net results of discontinued operations.................... 45 31 69
------ ----- -----
Earnings before cumulative effect of change in accounting
principle................................................. 104 54 730
Cumulative effect of change in accounting principle......... -- 49 --
------ ----- -----
Net earnings................................................ 104 103 730
Preferred stock dividends................................... 10 10 10
------ ----- -----
Net earnings applicable to common shareholders.............. $ 94 93 720
====== ===== =====
</Table>
66
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS -- (CONTINUED)
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
(IN MILLIONS, EXCEPT
PER SHARE AMOUNTS)
<S> <C> <C> <C>
Basic net earnings per share:
Earnings from continuing operations.................. $ 0.32 0.09 5.13
Net results of discontinued operations............... 0.29 0.25 0.53
Cumulative effect of change in accounting
principle........................................... -- 0.39 --
------ ----- -----
Net earnings......................................... $ 0.61 0.73 5.66
====== ===== =====
Diluted net earnings per share:
Earnings from continuing operations............... 0.32 0.09 4.97
Net results of discontinued operations............ 0.29 0.25 0.53
Cumulative effect of change in accounting
principle....................................... -- 0.38 --
------ ----- -----
Net earnings...................................... $ 0.61 0.72 5.50
====== ===== =====
Weighted average common shares outstanding:
Basic............................................. 155 128 127
====== ===== =====
Diluted........................................... 156 130 132
====== ===== =====
</Table>
See accompanying notes to consolidated financial statements.
67
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<Table>
<Caption>
ACCUMULATED UNAMORTIZED
ADDITIONAL OTHER RESTRICTED
PREFERRED COMMON PAID-IN ACCUMULATED COMPREHENSIVE STOCK
STOCK STOCK CAPITAL DEFICIT LOSS AWARDS
--------- ------ ---------- ----------- ------------- -----------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Balance as of December 31, 1999.............. $1 13 3,492 (909) (65) --
Comprehensive earnings:
Net earnings............................... -- -- -- 730 -- --
Other comprehensive earnings (loss), net of
tax:
Foreign currency translation
adjustments............................ -- -- -- -- (10) --
Minimum pension liability adjustment..... -- -- -- -- 1 --
Unrealized loss on marketable
securities............................. -- -- -- -- (11) --
-- -- ----- ---- ---- --
Other comprehensive loss............... -- -- -- -- -- --
-- -- ----- ---- ---- --
Comprehensive earnings.....................
Stock issued................................. -- -- 69 (4) -- --
Stock repurchased............................ -- -- -- -- -- --
Tax benefit related to employee stock
options.................................... -- -- 3 -- -- --
Dividends on common stock.................... -- -- -- (22) -- --
Dividends on preferred stock................. -- -- -- (10) -- --
Grant of restricted stock awards............. -- -- -- -- -- (5)
Amortization of restricted stock awards...... -- -- -- -- -- 4
-- -- ----- ---- ---- --
Balance as of December 31, 2000.............. 1 13 3,564 (215) (85) (1)
Comprehensive earnings:
Net earnings............................... -- -- -- 103 -- --
Other comprehensive earnings (loss), net of
tax:
Foreign currency translation
adjustments............................ -- -- -- -- (107) --
Cumulative effect of change in accounting
principle.............................. -- -- -- -- (37) --
Reclassification adjustment for
derivative (gains) losses reclassified
into oil and gas sales................. -- -- -- -- (20) --
Change in fair value of financial
instruments............................ -- -- -- -- 216 --
Minimum pension liability adjustment..... -- -- -- -- (17) --
Unrealized gain on marketable
securities............................. -- -- -- -- 22 --
-- -- ----- ---- ---- --
Other comprehensive earnings........... -- -- -- -- -- --
-- -- ----- ---- ---- --
Comprehensive earnings.....................
Stock issued................................. -- -- 48 -- -- --
Stock repurchased............................ -- -- (14) -- -- --
Tax benefit related to employee stock
options.................................... -- -- 12 -- -- --
Dividends on common stock.................... -- -- -- (25) -- --
Dividends on preferred stock................. -- -- -- (10) -- --
Amortization of restricted stock awards...... -- -- -- -- -- 1
-- -- ----- ---- ---- --
Balance as of December 31, 2001.............. 1 13 3,610 (147) (28) --
Comprehensive loss:
Net earnings............................... -- -- -- 104 -- --
Other comprehensive earnings (loss), net of
tax:
Foreign currency translation
adjustments............................ -- -- -- -- 46 --
Reclassification adjustment for
derivative losses reclassified into oil
and gas sales.......................... -- -- -- -- (39) --
Change in fair value of financial
instruments............................ -- -- -- -- (217) --
Minimum pension liability adjustment..... -- -- -- -- (54) --
Unrealized loss on marketable
securities............................. -- -- -- -- (103) --
Impairment of marketable securities...... -- -- -- -- 128 --
-- -- ----- ---- ---- --
Other comprehensive loss............... -- -- -- -- -- --
-- -- ----- ---- ---- --
Comprehensive loss.........................
Stock issued................................. -- 3 1,562 -- -- --
Tax benefit related to employee stock
options.................................... -- -- 6 -- -- --
Dividends on common stock.................... -- -- -- (31) -- --
Dividends on preferred stock................. -- -- -- (10) -- --
Grant of restricted stock awards............. -- -- -- -- -- (3)
-- -- ----- ---- ---- --
Balance as of December 31, 2002.............. $1 16 5,178 (84) (267) (3)
== == ===== ==== ==== ==
<Caption>
TOTAL
TREASURY STOCKHOLDERS'
STOCK EQUITY
-------- -------------
(IN MILLIONS)
<S> <C> <C>
Balance as of December 31, 1999.............. (11) 2,521
Comprehensive earnings:
Net earnings............................... -- 730
Other comprehensive earnings (loss), net of
tax:
Foreign currency translation
adjustments............................ -- (10)
Minimum pension liability adjustment..... -- 1
Unrealized loss on marketable
securities............................. -- (11)
---- -----
Other comprehensive loss............... -- (20)
---- -----
Comprehensive earnings..................... 710
Stock issued................................. 21 86
Stock repurchased............................ (10) (10)
Tax benefit related to employee stock
options.................................... -- 3
Dividends on common stock.................... -- (22)
Dividends on preferred stock................. -- (10)
Grant of restricted stock awards............. -- (5)
Amortization of restricted stock awards...... -- 4
---- -----
Balance as of December 31, 2000.............. -- 3,277
Comprehensive earnings:
Net earnings............................... -- 103
Other comprehensive earnings (loss), net of
tax:
Foreign currency translation
adjustments............................ -- (107)
Cumulative effect of change in accounting
principle.............................. -- (37)
Reclassification adjustment for
derivative (gains) losses reclassified
into oil and gas sales................. -- (20)
Change in fair value of financial
instruments............................ -- 216
Minimum pension liability adjustment..... -- (17)
Unrealized gain on marketable
securities............................. -- 22
---- -----
Other comprehensive earnings........... -- 57
---- -----
Comprehensive earnings..................... 160
Stock issued................................. -- 48
Stock repurchased............................ (190) (204)
Tax benefit related to employee stock
options.................................... -- 12
Dividends on common stock.................... -- (25)
Dividends on preferred stock................. -- (10)
Amortization of restricted stock awards...... -- 1
---- -----
Balance as of December 31, 2001.............. (190) 3,259
Comprehensive loss:
Net earnings............................... -- 104
Other comprehensive earnings (loss), net of
tax:
Foreign currency translation
adjustments............................ -- 46
Reclassification adjustment for
derivative losses reclassified into oil
and gas sales.......................... -- (39)
Change in fair value of financial
instruments............................ -- (217)
Minimum pension liability adjustment..... -- (54)
Unrealized loss on marketable
securities............................. -- (103)
Impairment of marketable securities...... -- 128
---- -----
Other comprehensive loss............... -- (239)
---- -----
Comprehensive loss......................... (135)
Stock issued................................. 2 1,567
Tax benefit related to employee stock
options.................................... -- 6
Dividends on common stock.................... -- (31)
Dividends on preferred stock................. -- (10)
Grant of restricted stock awards............. -- (3)
---- -----
Balance as of December 31, 2002.............. (188) 4,653
==== =====
</Table>
See accompanying notes to consolidated financial statements.
68
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Earnings from continuing operations....................... $ 59 23 661
Adjustments to reconcile earnings from continuing
operations to net cash provided by operating activities:
Depreciation, depletion and amortization of property and
equipment.............................................. 1,211 831 662
Amortization of goodwill................................ -- 34 41
Accretion of discounts on long-term debt, net........... 33 26 3
Effects of changes in foreign currency exchange rates... (1) 11 3
Change in fair value of financial instruments........... (28) 2 --
Reduction of carrying value of oil and gas properties... 651 979 --
Impairment of ChevronTexaco Corporation common stock.... 205 -- --
Operating cash flows from discontinued operations....... 28 134 110
Loss (gain) on sale of assets........................... (2) 2 (1)
Deferred income tax expense (benefit)................... (216) (43) 257
Other................................................... (9) (3) 4
Changes in assets and liabilities, net of effects of
acquisitions of businesses:
(Increase) decrease in:
Accounts receivable................................ (80) 203 (272)
Inventories........................................ 10 12 (5)
Income taxes receivable............................ -- (68) --
Investments and other current assets............... 12 (8) 3
(Decrease) increase in:
Accounts payable................................... (74) 37 78
Income taxes payable............................... 21 (129) 61
Accrued interest and expenses...................... 36 (46) 2
Deferred revenue................................... (46) (63) 8
Long-term other liabilities........................ (56) (24) (26)
------- ------ ------
Net cash provided by operating activities............. 1,754 1,910 1,589
------- ------ ------
CASH FLOWS FROM INVESTING ACTIVITIES
Proceeds from sale of property and equipment.............. 1,067 41 101
Proceeds from sale of investments......................... -- -- 13
Capital expenditures, including acquisitions of
businesses.............................................. (3,426) (5,235) (1,148)
Discontinued operations (including net proceeds from sale
of $336 million in 2002)................................ 316 (91) (132)
Increase in other assets.................................. (3) -- (7)
------- ------ ------
Net cash used in investing activities................. (2,046) (5,285) (1,173)
------- ------ ------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings of long-term debt, net of
issuance costs.......................................... 6,067 6,199 2,580
Principal payments on long-term debt...................... (5,657) (2,638) (2,952)
Issuance of common stock, net of issuance costs........... 32 48 51
Repurchase of common stock................................ -- (204) (10)
Issuance of treasury stock................................ -- -- 25
Dividends paid on common stock............................ (31) (25) (22)
Dividends paid on preferred stock......................... (10) (10) (10)
Decrease in long-term other liabilities................... -- -- (52)
------- ------ ------
Net cash provided by (used in) financing activities... 401 3,370 (390)
------- ------ ------
Effect of exchange rate changes on cash..................... -- (6) (1)
------- ------ ------
Net increase (decrease) in cash and cash equivalents........ 109 (11) 25
Cash and cash equivalents at beginning of year.............. 183 194 169
------- ------ ------
Cash and cash equivalents at end of year.................... $ 292 183 194
======= ====== ======
</Table>
See accompanying notes to consolidated financial statements.
69
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2002, 2001 AND 2000
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting policies used by Devon Energy Corporation and subsidiaries
("Devon") reflect industry practices and conform to accounting principles
generally accepted in the United States of America. The more significant of such
policies are briefly discussed below.
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Devon is engaged primarily in oil and gas exploration, development and
production, and the acquisition of producing properties. Such activities
domestically are concentrated in four geographic areas:
- the Permian Basin within Texas and New Mexico;
- the Rocky Mountains area of the United States stretching from the
Canadian Border into northern New Mexico
- the Mid-Continent area of the central and southern United States; and
- the Gulf Coast, which includes properties located primarily in the
onshore South Texas and South Louisiana areas and offshore in the Gulf of
Mexico;
Devon's Canadian activities are located primarily in the Western Canadian
Sedimentary Basin, and Devon's international activities -- outside of North
America -- are located primarily in Azerbaijan, Brazil, China and West Africa.
Devon also has a marketing and midstream business which is responsible for
marketing natural gas, crude oil and NGLs, and the construction and operation of
pipelines, storage and treating facilities and gas processing plants. These
services are performed for Devon as well as for unrelated third parties.
Devon's share of the assets, liabilities, revenues and expenses of
affiliated partnerships and the accounts of its wholly-owned subsidiaries are
included in the accompanying consolidated financial statements. All significant
intercompany accounts and transactions have been eliminated in consolidation.
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities at
the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Significant items subject to such
estimates and assumptions include the carrying value of oil and gas properties,
goodwill impairment assessment, deferred income taxes, valuation of derivative
instruments, and obligations related to employee benefits. Actual amounts could
differ from those estimates.
PROPERTY AND EQUIPMENT
Devon follows the full cost method of accounting for its oil and gas
properties. Accordingly, all costs incidental to the acquisition, exploration
and development of oil and gas properties, including costs of undeveloped
leasehold, dry holes and leasehold equipment, are capitalized. Internal costs
incurred that are directly identified with acquisition, exploration and
development activities undertaken by Devon for its own account, and which are
not related to production, general corporate overhead or similar activities, are
also capitalized. For the years 2002, 2001 and 2000, such internal costs
capitalized totaled $97 million, $77 million and $62 million, respectively.
70
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Unproved properties are excluded from amortized capitalized costs until it
is determined whether or not proved reserves can be assigned to such properties.
Devon assesses its unproved properties for impairment at least annually.
Net capitalized costs are limited to the estimated future net revenues,
discounted at 10% per annum, from proved oil, natural gas and natural gas
liquids reserves plus the cost of properties not subject to amortization. Such
limitations are imposed separately on a country-by-country basis and are tested
quarterly. Capitalized costs are depleted by an equivalent unit-of-production
method, converting gas to oil at the ratio of six thousand cubic feet of natural
gas to one barrel of oil. Depletion is calculated using the capitalized costs
plus the estimated future expenditures (based on current costs) to be incurred
in developing proved reserves, and the estimated dismantlement and abandonment
costs, net of estimated salvage values. No gain or loss is recognized upon
disposal of oil and gas properties unless such disposal significantly alters the
relationship between capitalized costs and proved reserves. All costs related to
production activities, including workover costs incurred solely to maintain or
increase levels of production from an existing completion interval, are charged
to expense as incurred.
Depreciation and amortization of other property and equipment, including
leasehold improvements, are provided using the straight-line method based on
estimated useful lives from three to 39 years.
MARKETABLE SECURITIES AND OTHER INVESTMENTS
Devon accounts for certain investments in debt and equity securities by
following the requirements of Statement of Financial Accounting Standards
("SFAS") No. 115, Accounting for Certain Investments in Debt and Equity
Securities. This standard requires that, except for debt securities classified
as "held-to-maturity," investments in debt and equity securities must be
reported at fair value. As a result, Devon's investment in approximately 7.1
million shares of ChevronTexaco Corporation ("ChevronTexaco") common stock,
which is classified as "available-for-sale," is reported at fair value. Except
for unrealized losses that are determined to be "other than temporary", the tax
effected unrealized gain or loss is recognized in other comprehensive loss and
reported as a separate component of stockholders' equity. Devon's investments in
other short-term securities are also classified as "available-for-sale."
The market value of Devon's investment in ChevronTexaco as of December 31,
2002, was approximately $472 million. Devon acquired these shares in its August
1999 acquisition of PennzEnergy Company. The shares are deposited with an
exchange agent for possible exchange for $760 million of debentures that are
exchangeable into the ChevronTexaco shares. The debentures, which mature in
August 2008, were also assumed by Devon in the 1999 PennzEnergy acquisition.
Devon initially recorded the ChevronTexaco common shares at their market
value at the closing date of the PennzEnergy acquisition, which was $95.38 per
share, or an aggregate value of $677 million. Since then, as the ChevronTexaco
shares have fluctuated in market value, the value of the shares on Devon's
balance sheet has been adjusted to the applicable market value. Through
September 30, 2002, any decreases in the value of the ChevronTexaco common
shares were determined by Devon to be temporary in nature. Therefore, the
changes in value were recorded directly to stockholders' equity and were not
recorded in Devon's results of operations through September 30, 2002.
The determination that a decline in value of the ChevronTexaco shares is
temporary or other than temporary is subjective and influenced by many factors.
Among these factors are the significance of the decline as a percentage of the
original cost, the length of time the stock price has been below original cost,
the performance of the stock price in relation to the stock price of its
competitors within the industry and the market in general, and whether the
decline is attributable to specific adverse conditions affecting ChevronTexaco.
71
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Beginning in July 2002, the market value of ChevronTexaco common stock
began what has ultimately become a significant decline. The price per share
decreased from $88.50 at June 30, 2002, to $69.25 per share at September 30,
2002, and to $66.48 per share at December 31, 2002. The year-end price of $66.48
represents a 25% decline since June 30, 2002, and a 30% decline from the
original valuation in August 1999. As a result of the continuation of the
decline in value during the fourth quarter of 2002, Devon determined that the
decline is other than temporary, as that term is defined by accounting rules.
Therefore, the $205 million cumulative decrease in the value of the
ChevronTexaco common shares from the initial acquisition in August 1999 to
December 31, 2002, was recorded as a noncash charge to Devon's results of
operations in the fourth quarter of 2002. Net of the applicable tax benefit, the
charge reduced net earnings by $128 million.
Depending on the future performance of ChevronTexaco's common stock, Devon
may be required to record additional noncash charges in future periods if Devon
determines that a decline in the value of such stock is other than temporary.
GOODWILL
Goodwill represents the excess of the purchase price of business
combinations over the fair value of the net assets acquired.
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 as they were prior
to 2002, 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 to
$3.6 billion at the end of 2002. Devon performed its annual assessment of
goodwill in the fourth quarter of 2002. Based on this assessment, no impairment
of goodwill was required.
72
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 2000.
<Table>
<Caption>
FOR THE YEAR ENDED
DECEMBER 31,
---------------------
2002 2001 2000
----- ----- -----
(IN MILLIONS, EXCEPT
PER SHARE DATA)
<S> <C> <C> <C>
Net earnings applicable to common shareholders, as
reported.................................................. $ 94 93 720
Add back amortization of goodwill........................... -- 34 41
----- ----- -----
Net earnings applicable to common shareholders, as
adjusted.................................................. $ 94 127 761
===== ===== =====
Basic earnings per share:
Net earnings applicable to common shareholders, as
reported............................................... $0.61 0.73 5.66
Amortization of goodwill.................................. -- 0.26 0.32
----- ----- -----
Net earnings applicable to common shareholders, as
adjusted............................................... $0.61 0.99 5.98
===== ===== =====
Diluted earnings per share:
Net earnings applicable to common shareholders, as
reported............................................... $0.61 0.72 5.50
Amortization of goodwill.................................. -- 0.26 0.31
----- ----- -----
Net earnings applicable to common shareholders, as
adjusted............................................... $0.61 0.98 5.81
===== ===== =====
</Table>
REVENUE RECOGNITION AND GAS BALANCING
Oil and gas revenues are recognized when sold. During the course of normal
operations, Devon and other joint interest owners of natural gas reservoirs will
take more or less than their respective ownership share of the natural gas
volumes produced. These volumetric imbalances are monitored over the lives of
the wells' production capability. If an imbalance exists at the time the wells'
reserves are depleted, settlements are made among the joint interest owners
under a variety of arrangements.
Devon follows the sales method of accounting for gas production imbalances.
A liability is recorded when Devon's excess takes of natural gas volumes exceed
its estimated remaining recoverable reserves. No receivables are recorded for
those wells where Devon has taken less than its ownership share of gas
production.
Marketing and midstream revenues are recorded on the sales method at the
time products are sold or services are provided to third parties. Revenues and
expenses attributable to Devon's NGL purchase and processing contracts are
reported on a gross basis since Devon takes title to the products and has risks
and rewards of ownership.
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.
As of January 1, 2001, Devon adopted the provisions of SFAS No. 133,
Accounting for Derivative Instruments and Certain Hedging Activities and SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, an Amendment of SFAS No. 133. SFAS Nos. 133 and 138 require that all
derivative instruments be recorded on the balance sheet at their respective fair
values. In
73
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
accordance with the transition provisions of SFAS No. 133, Devon recorded a
net-of-tax cumulative-effect-type adjustment of $37 million loss in accumulated
other comprehensive loss ("AOCL") to recognize the fair value of all derivatives
that were designated as cash-flow hedging instruments. Additionally, Devon
recorded a net-of-tax cumulative-effect-type adjustment to net earnings of $49
million gain ($0.39 per basic share and $0.38 per diluted share) related to the
fair value of derivative instruments that did not qualify as hedges. This gain
related principally to the option embedded in Devon's debentures that are
exchangeable into shares of ChevronTexaco common stock.
All derivatives are recognized on the balance sheet at their fair value.
The majority of Devon's derivatives that qualify for hedge accounting treatment
are either "cash flow" hedges or "foreign currency cash flow" hedges
(collectively, "cash flow hedges"). Devon designates its cash flow hedge
derivatives as such on the date the derivative contract is entered into or the
date of a business combination which includes cash flow hedges. Devon formally
documents all relationships between hedging instruments and hedged items, as
well as its risk-management objective and strategy for undertaking various hedge
transactions. Devon also assesses, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging transactions are
highly effective in offsetting changes in cash flows of hedged items.
During 2002 and 2001, there were no gains or losses reclassified into
earnings as a result of the discontinuance of hedge accounting treatment for any
of Devon's derivatives.
By using derivative instruments to hedge exposures to changes in commodity
prices and exchange rates, Devon exposes itself to credit risk and market risk.
Credit risk is the failure of the counterparty to perform under the terms of the
derivative contract. To mitigate this risk, 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.
Market risk is the adverse effect on the value of a derivative instrument
that results from a change in interest rates, commodity prices, or currency
exchange rates. The market risk associated with commodity price and foreign
exchange contracts is managed by establishing and monitoring parameters that
limit the types and degree of market risk that may be undertaken. The oil and
gas reference prices upon which the hedging instruments are based reflect
various market indices that have a high degree of historical correlation with
actual prices received by Devon.
Devon does not hold or issue derivative instruments for speculative trading
purposes. Substantially all of Devon's commodity price swaps and costless price
collars, interest rate swaps, and foreign exchange rate swaps have been
designated as cash flow hedges. Changes in the fair value of these derivatives
are reported on the balance sheet in AOCL. These amounts are reclassified to oil
and gas sales or interest expense when the forecasted transaction takes place.
During the third quarter of 2001, Devon entered into foreign exchange
forward contracts to mitigate the effect of volatility in the Canadian-to-U.S.
dollar exchange rate on the Anderson acquisition. Under SFAS No. 133, these
derivative instruments were not considered hedges and, as such, the realized
gain of $30 million from settling these contracts is included in the 2001
consolidated statement of operations as other income.
Also, during the third quarter of 2001, Devon entered into interest rate
locks to reduce exposure to the variability in market interest rates,
specifically U.S. Treasury rates, in anticipation of the sale of the debt
securities discussed in Note 6. These derivative instruments were designated as
cash flow hedges. A $28 million loss was incurred on these interest rate locks.
This loss will be amortized into interest expense using the effective interest
method over the life of the debt securities.
74
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Devon recorded in its statements of operations a gain of $28 million and a
loss of $2 million for the years ended December 31, 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.
As of December 31, 2002, $147 million of net deferred losses on derivative
instruments accumulated in AOCL are expected to be reclassified to earnings
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 are primarily the production and sale of oil and gas which includes the
production hedged under the various derivative instruments. The maximum term
over which Devon is hedging exposures to the variability of cash flows for
commodity price risk is 24 months.
STOCK OPTIONS
Devon applies the intrinsic value-based method of accounting prescribed by
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees, and related interpretations, in accounting for its fixed plan stock
options. As such, compensation expense would be recorded on the date of grant
only if the current market price of the underlying stock exceeded the exercise
price. SFAS No. 123, Accounting for Stock-Based Compensation, established
accounting and disclosure requirements using a fair value-based method of
accounting for stock-based employee compensation plans. As allowed by SFAS No.
123, Devon has elected to continue to apply the intrinsic value-based method of
accounting described above, and has adopted the disclosure requirements of SFAS
No. 123.
Had Devon elected the fair value provisions of SFAS No. 123 and recognized
compensation expense over the vesting period based on the fair value of the
stock options granted as of their grant date, Devon's 2002, 2001 and 2000 pro
forma net earnings and pro forma net earnings per share would have differed from
the amounts actually reported as shown in the following table.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------
(IN MILLIONS, EXCEPT PER
SHARE AMOUNTS)
<S> <C> <C> <C>
Net earnings available to common shareholders:
As reported............................................... $ 94 93 720
Pro forma................................................. $ 78 79 702
Net earnings per share available to common shareholders:
As reported:
Basic.................................................. $0.61 0.73 5.66
Diluted................................................ $0.61 0.72 5.50
Pro forma:
Basic.................................................. $0.51 0.62 5.51
Diluted................................................ $0.50 0.61 5.36
</Table>
MAJOR PURCHASERS
No purchaser accounted for over 10% of revenues in 2002. In 2001 and 2000,
Enron Capital and Trade Resource Corporation accounted for 16% and 21%,
respectively, of Devon's combined oil, gas and natural gas liquids sales.
On December 2, 2001, Enron Corp. and certain of its subsidiaries filed
voluntary petitions for reorganization under Chapter 11 of the United States
Bankruptcy Code. Prior to this date, Devon had
75
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
terminated substantially all of its agreements to sell oil, gas or NGLs to Enron
related entities. Devon incurred $3 million of losses in 2001 for sales to Enron
related subsidiaries which were not collected prior to the bankruptcy filing.
INCOME TAXES
Devon accounts for income taxes using the asset and liability method,
whereby deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement
carrying amounts of assets and liabilities and their respective tax bases, as
well as the future tax consequences attributable to the future utilization of
existing tax net operating loss and other types of carryforwards. Deferred tax
assets and liabilities are measured using enacted tax rates expected to apply to
taxable income in the years in which those temporary differences and
carryforwards are expected to be recovered or settled. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in income in
the period that includes the enactment date. U.S. deferred income taxes have not
been provided on undistributed earnings of foreign operations which are being
permanently reinvested.
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses are reported net of amounts allocated
to working interest owners of the oil and gas properties operated by Devon and
net of amounts capitalized pursuant to the full cost method of accounting.
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. On October 25,
2002, Devon sold its Argentine operations to Petroleo Brasileiro S.A. for total
cash consideration of $90 million. On January 27, 2003, Devon sold its Egyptian
operations to IPR Transoil Corporation for total cash consideration of $7
million.
Under the provisions of SFAS No. 144, Devon has reclassified its
Indonesian, Argentine and Egyptian activities as discontinued operations. This
reclassification affects not only the 2002 presentation of financial results,
but also the presentation of all prior periods' results.
76
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The major classes of assets and liabilities of these discontinued
operations as of December 31, 2002, 2001 and 2000 and revenues from these
discontinued operations in 2002, 2001 and 2000 are presented below:
<Table>
<Caption>
AS OF DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
MAJOR CLASSES OF ASSETS AND LIABILITIES
Cash........................................................ $-- 10 34
Accounts receivable......................................... 7 48 36
Inventories................................................. -- 21 24
Other current assets........................................ -- 2 12
Property and equipment, net of accumulated depreciation,
depletion and amortization................................ -- 266 248
Other assets................................................ -- 7 7
--- ---- ----
Total assets.............................................. $ 7 354 361
=== ==== ====
Accounts payable -- trade................................... $-- 41 49
Income taxes payable........................................ -- 14 2
Accrued expense............................................. -- 1 1
Other liabilities........................................... -- 7 6
Deferred income taxes....................................... -- (7) (7)
--- ---- ----
Total liabilities......................................... $-- 56 51
=== ==== ====
</Table>
<Table>
<Caption>
FOR THE YEAR ENDED
DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
REVENUES
Oil sales................................................... $72 174 173
Gas sales................................................... 7 12 11
NGL sales................................................... 1 1 --
--- ---- ----
Total revenues............................................ $80 187 184
=== ==== ====
</Table>
NET EARNINGS PER COMMON SHARE
Basic earnings per share is computed by dividing income available to common
stockholders by the weighted average number of common shares outstanding for the
period. Diluted earnings per share reflects the potential dilution that could
occur if Devon's dilutive outstanding stock options were exercised (calculated
using the treasury stock method) and if Devon's zero coupon convertible senior
debentures were converted to common stock.
77
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table reconciles the net earnings and common shares
outstanding used in the calculations of basic and diluted earnings per share for
2002, 2001 and 2000.
<Table>
<Caption>
NET EARNINGS WEIGHTED
APPLICABLE TO AVERAGE NET
COMMON COMMON SHARES EARNINGS
STOCKHOLDERS OUTSTANDING PER SHARE
------------- ------------- ---------
(IN MILLIONS)
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2002:
Basic earnings per share......................... $ 94 155 0.61
Dilutive effect of potential common shares
issuable upon the exercise of outstanding
stock options................................. -- 1
---- ---- -----
Diluted earnings per share....................... $ 94 156 0.61
==== ==== =====
YEAR ENDED DECEMBER 31, 2001:
Basic earnings per share......................... $ 93 128 0.73
Dilutive effect of potential common shares
issuable upon the exercise of outstanding
stock options................................. -- 2
---- ---- -----
Diluted earnings per share....................... $ 93 130 0.72
==== ==== =====
YEAR ENDED DECEMBER 31, 2000:
Basic earnings per share......................... $720 127 5.66
Dilutive effect of:
Potential common shares issuable upon
conversion of senior convertible debentures
(the increase in net earnings is net of
income tax expense of $3)................... 5 3
Potential common shares issuable upon the
exercise of outstanding stock options....... -- 2
---- ---- -----
Diluted earnings per share....................... $725 132 5.50
==== ==== =====
</Table>
The senior convertible debentures included in the 2000 dilution
calculations were not included in the 2002 and 2001 dilution calculations
because the inclusion was anti-dilutive.
Certain options to purchase shares of Devon's common stock have been
excluded from the dilution calculations because the options' exercise price
exceeded the average market price of Devon's common stock during the applicable
year. The following information relates to these options.
<Table>
<Caption>
2002 2001 2000
---------------- ---------------- ----------------
<S> <C> <C> <C>
Options excluded from dilution calculation
(in millions)............................ 5 3 1
Range of exercise prices................... $45.49 - $89.66 $48.13 - $89.66 $55.54 - $89.66
Weighted average exercise price............ $ 50.85 $ 56.11 $ 66.64
</Table>
The excluded options for 2002 expire between January 24, 2003 and December
2, 2012.
COMPREHENSIVE EARNINGS OR LOSS
Devon's comprehensive earnings or loss information is included in the
accompanying consolidated statements of stockholders' equity. A summary of
accumulated other comprehensive earnings or loss as of
78
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 2002, 2001 and 2000, and changes during each of the years then
ended, is presented in the following table.
<Table>
<Caption>
CHANGE IN
FOREIGN FAIR VALUE MINIMUM UNREALIZED
CURRENCY OF PENSION GAIN (LOSS) ON
TRANSLATION FINANCIAL LIABILITY MARKETABLE
ADJUSTMENTS INSTRUMENTS ADJUSTMENTS SECURITIES TOTAL
----------- ----------- ----------- -------------- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
Balance as of December 31, 1999...... $ (28) -- (1) (36) (65)
2000 activity...................... (10) -- 1 (18) (27)
Deferred taxes..................... -- -- -- 7 7
----- ----- ---- ---- -----
2000 activity, net of deferred
taxes........................... (10) -- 1 (11) (20)
----- ----- ---- ---- -----
Balance as of December 31, 2000...... (38) -- -- (47) (85)
2001 activity...................... (107) 243 (28) 36 144
Deferred taxes..................... -- (84) 11 (14) (87)
----- ----- ---- ---- -----
2001 activity, net of deferred
taxes........................... (107) 159 (17) 22 57
----- ----- ---- ---- -----
Balance as of December 31, 2001...... (145) 159 (17) (25) (28)
2002 activity...................... 46 (379) (85) 41 (377)
Deferred taxes..................... -- 123 31 (16) 138
----- ----- ---- ---- -----
2002 activity, net of deferred
taxes........................... 46 (256) (54) 25 (239)
----- ----- ---- ---- -----
Balance as of December 31, 2002...... $ (99) (97) (71) -- (267)
===== ===== ==== ==== =====
</Table>
The 2002 activity for unrealized gain (loss) on marketable securities
includes additional unrealized losses of $164 million ($103 million net of
taxes), offset by the recognition of a $205 million loss ($128 million net of
taxes) in the statement of operations during 2002. The recognized loss was due
to the impairment of the ChevronTexaco common stock owned by Devon.
FOREIGN CURRENCY TRANSLATION ADJUSTMENTS
The assets and liabilities of certain foreign subsidiaries are prepared in
their respective local currencies and translated into U.S. dollars based on the
current exchange rate in effect at the balance sheet dates, while income and
expenses are translated at average rates for the periods presented. Translation
adjustments have no effect on net income and are included in accumulated other
comprehensive loss.
DIVIDENDS
Dividends on Devon's common stock were paid in 2002, 2001 and 2000 at a per
share rate of $0.05 per quarter. As adjusted for the pooling-of-interests method
of accounting followed for the 2000 Santa Fe Snyder merger, annual dividends per
share for 2002, 2001 and 2000 were $0.20, $0.20 and $0.17, respectively.
STATEMENTS OF CASH FLOWS
For purposes of the consolidated statements of cash flows, Devon considers
all highly liquid investments with original maturities of three months or less
to be cash equivalents.
79
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
COMMITMENTS AND CONTINGENCIES
Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability
has been incurred and the amount can be reasonably estimated.
Environmental expenditures are expensed or capitalized in accordance with
accounting principles generally accepted in the United States of America.
Liabilities for these expenditures are recorded when it is probable that
obligations have been incurred and the amounts can be reasonably estimated.
Reference is made to Note 11 for a discussion of amounts recorded for these
liabilities.
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 the discounted present 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."
The asset retirement cost equal to the discounted 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 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 previously estimated costs of dismantlement, removal, site
reclamation, and other similar activities in the total costs that are subject to
depreciation, depletion, and amortization. However, Devon did not record a
separate asset or liability for such amounts. Upon adoption of SFAS No. 143 on
January 1, 2003, Devon expects to record a cumulative-effect-type adjustment for
an increase to net earnings of between $10 million and $30 million, net of
deferred tax expense of between $5 million and $15 million. Additionally, Devon
expects to establish an asset retirement obligation of between $425 million and
$475 million, an increase to property and equipment of between $375 million and
$425 million and a decrease in accumulated DD&A of between $65 million and $95
million.
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 early adopted the provisions related to SFAS No. 145
during the fourth quarter 2002. With the adoption of SFAS No. 145, a loss of $6
million resulting from extinguishment of debt in 1999 was reclassified from
extraordinary loss to interest expense, and 1999's current income tax expense
was reduced by the $2 million tax benefit related to the loss from early
extinguishment.
80
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
In November 2002, the FASB issued Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness to Others, an interpretation of FASB Statements No.
5, 57 and 107 and a rescission of FASB Interpretation No. 34. This
Interpretation elaborates on the disclosures to be made by a guarantor in its
interim and annual financial statements about its obligations under guarantees
issued. The Interpretation also clarifies that a guarantor is required to
recognize, at inception of a guarantee, a liability for the fair value of the
obligation undertaken. The initial recognition and measurement provisions of the
Interpretation are applicable to guarantees issued or modified after December
31, 2002 and are not expected to have a material effect on Devon's financial
statements. The disclosure requirements are effective for financial statements
of interim and annual periods ending after December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment of FASB Statement No.
123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based
Compensation, to provide alternative methods of transition for a voluntary
change to the fair value method of accounting for stock-based employee
compensation. In addition, this Statement amends the disclosure requirements of
Statement No. 123 to require prominent disclosures in both annual and interim
financial statements. Certain of the disclosure modifications are required for
fiscal years ending after December 15, 2002 and are included in the notes to
these consolidated financial statements.
In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51. Interpretation No. 46 requires a company to consolidate a variable
interest entity if the company has a variable interest (or combination of
variable interests) that will absorb a majority of the entity's expected losses
if they occur, receive a majority of the entity's expected residual returns if
they occur, or both. A direct or indirect ability to make decisions that
significantly affect the results of the activities of a variable interest entity
is a strong indication that a company has one or both of the characteristics
that would require consolidation of the variable interest entity. Interpretation
No. 46 also requires additional disclosures regarding variable interest
entities. The new interpretation is effective immediately for variable interest
entities created after January 31, 2003, and is effective in the first interim
or annual period beginning after June 15, 2003, for variable interest entities
in which a company holds a variable interest that it acquired before February 1,
2003. Devon owns no interests in variable interest entities, and therefore this
new interpretation will not affect Devon's consolidated financial statements.
81
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RECLASSIFICATION
Certain of the 2001 and 2000 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 6).
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 allocation to assets and
liabilities as of January 24, 2002, are shown below.
<Table>
<Caption>
(IN MILLIONS,
EXCEPT SHARE PRICE)
-------------------
<S> <C>
Calculation and allocation of purchase price:
Shares of Devon common stock issued to Mitchell
stockholders........................................... 30
Average Devon stock price................................. $50.95
------
Fair value of common stock issued......................... $1,512
Cash paid to Mitchell stockholders, calculated at $31 per
outstanding common share of Mitchell................... 1,573
------
Fair value of Devon common stock and cash to be issued to
Mitchell stockholders.................................. 3,085
Plus estimated acquisition costs incurred................. 84
Plus fair value of Mitchell employee stock options assumed
by Devon............................................... 27
------
Total purchase price.............................. 3,196
Plus fair value of liabilities assumed by Devon:
Current liabilities....................................... 190
Long-term debt............................................ 506
Other long-term liabilities............................... 128
Deferred income taxes..................................... 796
------
Total purchase price plus liabilities assumed..... $4,816
======
Fair value of assets acquired by Devon:
Current assets............................................ $ 169
Proved oil and gas properties............................. 1,535
Unproved oil and gas properties........................... 639
Marketing and midstream facilities and equipment.......... 1,000
Other property and equipment.............................. 15
Other assets.............................................. 103
Goodwill (none deductible for income taxes)............... 1,355
------
Total fair value of assets acquired............... $4,816
======
</Table>
82
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ANDERSON EXPLORATION LTD. ACQUISITION
On October 15, 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 the $3.0 billion
senior unsecured term loan credit facility (see Note 6).
Devon acquired Anderson to increase the scope of its Canadian operations,
for the exposure to north Canada's exploratory areas and to increase exposure to
the North American natural gas market.
The calculation of the purchase price and the allocation to assets and
liabilities as of October 15, 2001, are shown below.
<Table>
<Caption>
(IN MILLIONS,
EXCEPT SHARE PRICE)
-------------------
<S> <C>
Calculation and allocation of purchase price:
Number of Anderson common shares outstanding.............. 132
Acquisition price per share............................... $25.68
------
Cash paid to Anderson stockholders........................ $3,386
Cash paid to settle Anderson employees' stock options and
appreciation rights.................................... 92
------
3,478
Plus estimated acquisition costs incurred................. 35
------
Total purchase price.............................. 3,513
Plus fair value of liabilities assumed by Devon:
Current liabilities....................................... 251
Long-term debt............................................ 1,017
Other long-term liabilities............................... 3
Fair value of financial instruments....................... 30
Deferred income taxes..................................... 1,407
------
Total purchase price plus liabilities assumed..... $6,221
======
Fair value of assets acquired by Devon:
Current assets............................................ $ 214
Proved oil and gas properties............................. 2,605
Unproved oil and gas properties........................... 1,432
Other property and equipment.............................. 21
Goodwill (none deductible for income tax purposes)........ 1,949
------
Total fair value of assets acquired............... $6,221
======
</Table>
PRO FORMA INFORMATION
Set forth in the following table is certain unaudited pro forma financial
information for the years ended December 31, 2002 and 2001. The information 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
83
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 year ended December 31,
2001 include $34 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.
84
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
PRO FORMA
INFORMATION YEAR
ENDED
DECEMBER 31
-----------------
2002 2001
------ ------
(IN MILLIONS,
EXCEPT PER SHARE
AMOUNTS AND
PRODUCTION
VOLUMES)
(UNAUDITED)
<S> <C> <C>
REVENUES
Oil sales................................................. $ 911 1,059
Gas sales................................................. 2,155 3,133
Natural gas liquids sales................................. 280 306
Marketing and midstream revenues.......................... 1,069 1,238
------ ------
Total revenues...................................... 4,415 5,736
------ ------
OPERATING COSTS AND EXPENSES
Lease operating expenses.................................. 625 705
Transportation costs...................................... 157 155
Production taxes.......................................... 112 148
Marketing and midstream operating costs and expenses...... 873 1,085
Depreciation, depletion and amortization of property and
equipment............................................... 1,230 1,358
Amortization of goodwill.................................. -- 34
General and administrative expenses....................... 224 205
Expenses related to mergers............................... -- 1
Reduction of carrying value of oil and gas properties..... 651 1,136
------ ------
Total operating costs and expenses.................. 3,872 4,827
------ ------
Earnings from operations.................................... 543 909
OTHER INCOME (EXPENSES)
Interest expense.......................................... (534) (507)
Effects of changes in foreign currency exchange rates..... 1 (19)
Change in fair value of financial instruments............. 28 (15)
Impairment of ChevronTexaco Corporation common stock...... (205) --
Other income.............................................. 34 68
------ ------
Net other expenses.................................. (676) (473)
------ ------
Earnings (loss) from continuing operations before income tax
expense (benefit) and cumulative effect of change in
accounting principle...................................... $ (133) 436
INCOME TAX EXPENSE (BENEFIT)
Current................................................... 23 55
Deferred.................................................. (215) 96
------ ------
Total income tax expense (benefit).................. (192) 151
------ ------
Earnings from continuing operations before cumulative effect
of change in accounting principle......................... 59 285
DISCONTINUED OPERATIONS
Results of discontinued operations before income taxes
(including net gain on disposal of $31 million in
2002)................................................... 54 56
Total income tax expense.................................. 9 25
------ ------
Net results of discontinued operations.................... 45 31
------ ------
Earnings before cumulative effect of change in accounting
principle................................................. 104 316
Cumulative effect of change in accounting principle......... -- 49
------ ------
Net earnings................................................ 104 365
Preferred stock dividends................................... 10 10
------ ------
Net earnings applicable to common stockholders.............. $ 94 355
====== ======
</Table>
85
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
PRO FORMA
INFORMATION YEAR
ENDED
DECEMBER 31
-----------------
2002 2001
------ ------
(IN MILLIONS,
EXCEPT PER SHARE
AMOUNTS AND
PRODUCTION
VOLUMES)
(UNAUDITED)
<S> <C> <C>
Basic earnings per average common share outstanding:
Earnings from continuing operations................. $ 0.31 1.75
Net results of discontinued operations.............. 0.29 0.21
Cumulative effect of change in accounting
principle........................................... -- 0.31
------ ------
Net earnings........................................ $ 0.60 2.27
====== ======
Diluted earnings per average common share outstanding:
Earnings from continuing operations................. $ 0.31 1.73
Net results of discontinued operations.............. 0.29 0.20
Cumulative effect of change in accounting
principle........................................... -- 0.30
------ ------
Net earnings........................................ $ 0.60 2.23
====== ======
Weighted average common shares outstanding -- basic......... 157 157
Weighted average common shares outstanding -- diluted....... 158 164
Production volumes:
Oil (MMBbls).............................................. 42 50
Gas (Bcf)................................................. 771 802
NGLs (MMBbls)............................................. 20 17
MMBoe..................................................... 191 201
</Table>
SANTA FE SNYDER MERGER
Devon closed its merger with Santa Fe Snyder Corporation ("Santa Fe
Snyder") on August 29, 2000. The merger was accounted for using the
pooling-of-interests method of accounting for business combinations.
Accordingly, all operational and financial information contained herein includes
the combined amounts for Devon and Santa Fe Snyder for all periods presented.
Devon issued approximately 41 million shares of its common stock to the
former stockholders of Santa Fe Snyder based on an exchange ratio of 0.22 shares
of Devon common stock for each share of Santa Fe Snyder common stock. Because
the merger was accounted for using the pooling-of-interests method, all combined
share information has been retroactively restated to reflect the exchange ratio.
During 2000, Devon recorded a pre-tax charge of $60 million ($37 million
net of tax) for direct costs related to the Santa Fe Snyder merger.
3. SUPPLEMENTAL CASH FLOW INFORMATION
Cash payments (refunds) for interest and income taxes in 2002, 2001 and
2000 are presented below:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Interest paid............................................... $248 118 155
Income taxes paid (refunded)................................ $(12) 185 80
</Table>
86
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The 2002 Mitchell acquisition and the 2001 Anderson acquisition involved
non-cash consideration as presented below:
<Table>
<Caption>
2002 2001
------ -----
(IN MILLIONS)
<S> <C> <C>
Value of common stock issued................................ $1,512 --
Employee stock options assumed.............................. 27 --
Liabilities assumed......................................... 824 1,301
Deferred tax liability created.............................. 796 1,407
------ -----
Fair value of assets acquired with non-cash consideration... $3,159 2,708
====== =====
</Table>
4. ACCOUNTS RECEIVABLE
The components of accounts receivable included the following:
<Table>
<Caption>
DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids revenue accruals........... $422 275 402
Joint interest billings................................... 102 145 123
Marketing and midstream revenues.......................... 73 1 --
Other..................................................... 52 72 41
---- --- ---
649 493 566
Allowance for doubtful accounts........................... (10) (4) (4)
---- --- ---
Net accounts receivable................................... $639 489 562
==== === ===
</Table>
87
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. PROPERTY AND EQUIPMENT
Property and equipment included the following:
<Table>
<Caption>
DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Oil and gas properties:
Subject to amortization................................. $15,020 12,580 8,555
Not subject to amortization:
Acquired in 2002..................................... 730 -- --
Acquired in 2001..................................... 1,338 1,638 --
Acquired in 2000..................................... 52 65 74
Acquired prior to 2000............................... 169 226 240
Accumulated depreciation, depletion and amortization.... (7,796) (6,048) (4,382)
------- ------ ------
Net oil and gas properties......................... 9,513 8,461 4,487
------- ------ ------
Other property and equipment.............................. 1,477 390 222
Accumulated depreciation and amortization................. (138) (89) (47)
------- ------ ------
Net other property and equipment................... 1,339 301 175
------- ------ ------
Property and equipment, net of accumulated depreciation,
depletion and amortization.............................. $10,852 8,762 4,662
======= ====== ======
</Table>
The costs not subject to amortization relate to unproved properties which
are excluded from amortized capital costs until it is determined whether or not
proved reserves can be assigned to such properties. The excluded properties are
assessed for impairment at least annually. Subject to industry conditions,
evaluation of most of these properties, and the inclusion of their costs in the
amortized capital costs is expected to be completed within five years.
Depreciation, depletion and amortization of property and equipment
consisted of the following components:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
--------------------
2002 2001 2000
------ ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Depreciation, depletion and amortization of oil and gas
properties................................................ $1,106 793 632
Depreciation and amortization of other property and
equipment................................................. 97 30 23
Amortization of other assets................................ 8 8 7
------ --- ---
Total.................................................. $1,211 831 662
====== === ===
</Table>
88
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. LONG-TERM DEBT AND RELATED EXPENSES
A summary of Devon's long-term debt is as follows:
<Table>
<Caption>
DECEMBER 31,
----------------------
2002 2001 2000
------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C>
Borrowings under credit facilities with banks............... $ -- 50 147
Commercial paper borrowings................................. -- 75 --
$3 billion term loan credit facility........................ 1,135 1,046 --
Debentures exchangeable into shares of ChevronTexaco
Corporation common stock:
4.90% due August 15, 2008................................. 444 444 444
4.95% due August 15, 2008................................. 316 316 316
Discount on exchangeable debentures....................... (98) (111) --
Zero coupon convertible senior debentures exchangeable into
shares of Devon Energy Corp. common stock, 3.875% due June
27, 2020.................................................. 388 374 360
Other debentures and notes:
6.75% due February 15, 2004............................... 211 -- --
8.05% due June 15, 2004................................... 125 125 125
7.25% due July 18, 2005................................... 111 110 --
7.42% due October 1, 2005................................. -- 23 --
7.57% due October 4, 2005................................. -- 31 --
10.25% due November 1, 2005............................... 236 236 250
6.55% due August 2, 2006.................................. 127 126 --
8.75% due June 15, 2007................................... -- 175 175
10.125% due November 15, 2009............................. 177 177 200
6.75% due March 15, 2011.................................. 400 400 --
6.875% due September 30, 2011............................. 1,750 1,750 --
7.875% due September 30, 2031............................. 1,250 1,250 --
7.95% due April 15, 2032.................................. 1,000 -- --
Fair value adjustment on 8.05% notes related to interest
rate swap.............................................. 5 -- --
Net (discount) premium on other debentures and notes...... (15) (8) 32
------ ----- -----
7,562 6,589 2,049
Less amount classified as current........................... -- -- --
------ ----- -----
Long-term debt.............................................. $7,562 6,589 2,049
====== ===== =====
</Table>
89
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Maturities of long-term debt as of December 31, 2002, excluding the $113
million of discounts net of premiums and the $5 million fair value adjustment,
are as follows (in millions):
<Table>
<S> <C>
2003........................................................ $ --
2004........................................................ 336
2005........................................................ 347
2006........................................................ 1,262
2007........................................................ --
2008 and thereafter......................................... 5,725
------
Total....................................................... $7,670
======
</Table>
CREDIT FACILITIES WITH BANKS
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 December 31, 2002, there were no
borrowings outstanding under the $725 million U.S. Facility. The available
capacity under the U.S. Facility as of December 31, 2002, net of $25 million of
outstanding letters of credit, was $700 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 December
31, 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 weighted average interest rate on the $50 million
and $147 million outstanding under the previous facilities at December 31, 2001
and 2000, was 4.8% and 6.1%, respectively.
The agreements governing the Credit Facilities contain certain covenants
and restrictions, including a maximum debt-to-capitalization ratio. At December
31, 2002, Devon was in compliance with such covenants and restrictions.
90
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 December 31, 2002, C$109 million ($69 million
converted to U.S. dollars using the December 31, 2002 exchange rate) of letters
of credit were issued under the LOC Facility primarily for Canadian drilling
commitments.
COMMERCIAL PAPER
On August 29, 2000, Devon entered into a commercial paper program. Devon
may borrow up to $725 million under the commercial paper program. Total
borrowings under the U.S. Facility and the commercial paper program may not
exceed $725 million. The commercial paper borrowings may have terms of up to 365
days and bear interest at rates agreed to at the time of the borrowing. The
interest rate is based on a standard index such as the Federal Funds Rate,
London Interbank Offered Rate (LIBOR), or the money market rate as found on the
commercial paper market. As of December 31, 2002, Devon had no commercial paper
debt outstanding. As of December 31, 2001, Devon had $75 million of borrowings
under its commercial paper program at an average rate of 3.5%. Because Devon had
the intent and ability to refinance the balance due with borrowings under its
U.S. Facility, the $75 million outstanding under the commercial paper program
was classified as long-term debt on the December 31, 2001 consolidated balance
sheet.
$3 BILLION TERM LOAN CREDIT FACILITY
On October 12, 2001, Devon and its wholly-owned financing subsidiary Devon
Financing Corporation, U.L.C. ("Devon Financing") entered into a new $3 billion
senior unsecured term loan credit facility. The facility has a term of five
years. Devon and Devon Financing may borrow funds under this facility subject to
conditions usual in commercial transactions of this nature, including the
absence of any default under this facility. Interest on borrowings under this
facility may be based, at the borrower's option, on LIBOR or on UBS Warburg
LLC's base rate (which is the higher of UBS Warburg's prime commercial lending
rate and the weighted average of rates on overnight Federal funds transactions
with members of the Federal Reserve System plus 0.50%).
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 December 31, 2002, the average interest
rate on this facility was 2.5%.
Prior to December 31, 2001, Devon borrowed $1 billion under this 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 December 31, 2002, $1.9 billion of the
original $3 billion balance had been 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 $1.4 billion from the sale of certain oil
and gas properties, of which $1.1 billion was used to pay down debt.
91
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The terms of this facility require repayment of the debt during the
following periods:
<Table>
<Caption>
(IN MILLIONS)
<S> <C>
April 15, 2006.............................................. $ 335
October 15, 2006............................................ 800
------
Total..................................................... $1,135
======
</Table>
This credit facility contains certain covenants and restrictions, including
a maximum allowed debt-to-capitalization ratio as defined in the credit
facility. At December 31, 2002, Devon was in compliance with such covenants and
restrictions.
EXCHANGEABLE DEBENTURES
The exchangeable debentures consist of $444 million of 4.90% debentures and
$316 million of 4.95% debentures. The exchangeable debentures were issued on
August 3, 1998 and mature August 15, 2008. The exchangeable debentures were
callable beginning August 15, 2000, initially at 104.0% of principal and at
prices declining to 100.5% of principal on or after August 15, 2007. The
exchangeable debentures are exchangeable at the option of the holders at any
time prior to maturity, unless previously redeemed, for shares of ChevronTexaco
common stock. In lieu of delivering ChevronTexaco common stock, Devon may, at
its option, pay to any holder an amount of cash equal to the market value of the
ChevronTexaco common stock to satisfy the exchange request. However, at
maturity, the holders will receive an amount at least equal to the face value of
the debt outstanding. Such amount will either be in cash or in a combination of
cash and ChevronTexaco common stock.
As of December 31, 2002, Devon beneficially owned approximately 7.1 million
shares of ChevronTexaco common stock. These shares have been deposited with an
exchange agent for possible exchange for the exchangeable debentures. Each
$1,000 principal amount of the exchangeable debentures is exchangeable into
9.3283 shares of ChevronTexaco common stock, an exchange rate equivalent to
$107 7/32 per share of ChevronTexaco stock.
The exchangeable debentures were assumed as part of the PennzEnergy merger.
The fair values of the exchangeable debentures were determined as of August 17,
1999, based on market quotations. The fair value approximated the face value of
the exchangeable debentures. As a result, no premium or discount was recorded on
these exchangeable debentures. However, pursuant to the adoption of SFAS No. 133
effective January 1, 2001, these debentures were revalued as of August 17, 1999.
Under SFAS No. 133, the total fair value of the debentures was allocated between
the interest-bearing debt and the option to exchange ChevronTexaco common stock
that is embedded in the debentures. Accordingly, the debt portion of the
debentures was reduced by $140 million as of August 17, 1999. This discount is
being accreted using the effective interest method, and has raised the effective
interest rate on the debentures to 7.76% in 2001 compared to 4.92% prior to
2001.
ZERO COUPON CONVERTIBLE DEBENTURES
In June 2000, Devon privately sold zero coupon convertible senior
debentures. The debentures were sold at a price of $464.13 per debenture with a
yield to maturity of 3.875% per annum. Each of the 760,000 debentures is
convertible into 5.7593 shares of Devon common stock. Devon may call the
debentures at any time after five years, and a debenture holder has the right to
require Devon to repurchase the debentures after five, 10 and 15 years, at the
issue price plus accrued original issue discount and interest. The first put
date is June 26, 2005, at an accreted value of $427 million. Devon has the right
to satisfy its obligation by paying cash or issuing shares of Devon common stock
with a value equal to its obligation. Devon's proceeds were approximately $346
million, net of debt issuance costs of approximately
92
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$7 million. Devon used the proceeds from the sale of these debentures to pay
down other domestic long-term debt.
OTHER DEBENTURES AND NOTES
In connection with the Mitchell acquisition, Devon assumed $211 million of
6.75% senior notes due 2004. The fair value of these senior notes approximated
the face value. As a result, no premium or discount was recorded on these senior
notes.
In June 1999, Devon issued $125 million of 8.05% notes due 2004. The notes
were issued for 98.758% of face value and Devon received total proceeds of $122
million after deducting related costs and expenses of $2 million. The notes,
which mature June 15, 2004, are redeemable, upon not less than thirty nor more
than sixty days notice, as a whole or in part, at the option of Devon. The notes
are general unsecured obligations of Devon.
In connection with the Anderson acquisition, Devon assumed $702 million of
senior notes. The table below summarizes the debt assumed, the fair value of the
debt at October 15, 2001, and the effective interest rate of the debt assumed
after determining the fair values of the respective notes using October 15,
2001, market interest rates. The premiums and discounts are being amortized or
accreted using the effective interest method. All of the notes are general
unsecured obligations of Devon.
<Table>
<Caption>
FAIR VALUE OF EFFECTIVE RATE OF
DEBT ASSUMED DEBT ASSUMED DEBT ASSUMED
- ------------ ------------- -----------------
(IN MILLIONS)
<S> <C> <C>
7.25% senior notes due 2005.............................. $116 6.3%
7.42% senior notes due 2005.............................. $ 24 5.7%
7.57% senior notes due 2005.............................. $ 33 5.7%
6.55% senior notes due 2006.............................. $129 6.5%
6.75% senior notes due 2011.............................. $400 6.8%
</Table>
Devon recorded a $2 million early retirement premium in 2001 related to the
early retirement of the above 7.57% and 7.42% senior notes.
The 10.25% and 10.125% debentures were assumed as part of the PennzEnergy
merger. The fair values of the respective debentures were determined using
August 17, 1999, market interest rates. As a result, premiums were recorded on
these debentures which lowered their effective interest rates to 8.3% and 8.9%
on the $236 million of 10.25% debentures and $177 million of 10.125% debentures,
respectively. The premiums are being amortized using the effective interest
method.
During October 2001, Devon repurchased $14 million and $23 million of its
10.25% debentures and 10.125% debentures, respectively. Devon recorded an early
retirement premium of $5 million related to this repurchase.
On October 3, 2001, Devon, through Devon Financing, sold $1.75 billion of
6.875% notes due September 30, 2011 and $1.25 billion of 7.875% debentures due
September 30, 2031. The debt securities are unsecured and unsubordinated
obligations of Devon Financing. Devon has fully and unconditionally guaranteed
on an unsecured and unsubordinated basis the obligations of Devon Financing
under the debt securities. The proceeds from the issuance of these debt
securities were used to fund a portion of the Anderson acquisition.
The $3 billion of debt securities were structured in a manner that results
in an expected weighted average after-tax borrowing rate of approximately 1.65%.
93
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Interest on the debt securities is payable by Devon Financing semiannually
on March 30 and September 30 of each year. The indenture governing the debt
securities limits both Devon Financing's and Devon's ability to incur debt
secured by liens or enter into mergers or consolidations, or transfer all or
substantially all of their respective assets, unless the successor company
assumes Devon Financing's or Devon's obligations under the indenture.
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 subordinated notes due June 15, 2007. The notes were redeemed at
104.375% of principal, or approximately $183 million.
INTEREST EXPENSE
Following are the components of interest expense for the years 2002, 2001
and 2000:
<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Interest based on debt outstanding.......................... $499 200 157
Accretion (amortization) of debt discount (premium), net.... 13 10 (4)
Facility and agency fees.................................... 2 1 3
Amortization of capitalized loan costs...................... 8 3 2
Capitalized interest........................................ (4) (3) (3)
Early retirement premiums................................... 8 7 --
Other....................................................... 7 2 --
---- --- ---
Total interest expense...................................... $533 220 155
==== === ===
</Table>
EFFECTS OF CHANGES IN FOREIGN CURRENCY EXCHANGE RATES
The $400 million of 6.75% fixed-rate senior notes referred to in the first
table of this note are payable by a Canadian subsidiary of Devon. However, the
notes are denominated in U.S. dollars. Until their retirement in mid-January
2000, $225 million of additional notes denominated in U.S. dollars were owed by
another Canadian subsidiary. Changes in the exchange rate between the U.S.
dollar and the Canadian dollar from the dates the notes were issued or assumed
as part of an acquisition 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 of the debt are required to be
included in determining net earnings for the period in which the exchange rate
changed. The rate of conversion of Canadian dollars to U.S. dollars increased in
2002 and declined in 2001 and 2000. Therefore, $1 million of reduced expense was
recorded in 2002 and $11 million and $3 million of increased expense was
recorded in 2001 and 2000, respectively.
94
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. INCOME TAXES
At December 31, 2002, Devon had the following carryforwards available to
reduce future income taxes:
<Table>
<Caption>
YEARS OF CARRYFORWARD
TYPES OF CARRYFORWARD EXPIRATION AMOUNTS
- --------------------- ----------- -------------
(IN MILLIONS)
<S> <C> <C>
Net operating loss - U.S. federal.......................... 2008 - 2021 $ 10
Net operating loss - various states........................ 2003 - 2016 $119
Net operating loss - Canada................................ 2005 - 2009 $119
Net operating loss - International......................... Indefinite $ 63
Minimum tax credits........................................ Indefinite $164
</Table>
All of the carryforward amounts shown above have been utilized for
financial purposes to reduce the deferred tax liability.
The earnings (loss) before income taxes and the components of income tax
expense (benefit) for the years 2002, 2001 and 2000 were as follows:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2002 2001 2000
------ ------ -------
(IN MILLIONS)
<S> <C> <C> <C>
Earnings (loss) from continuing operations before income
taxes:
U.S. ..................................................... $ 354 458 872
Canada.................................................... (515) (357) 156
International............................................. 27 (73) 10
----- ----- ------
Total..................................................... $(134) 28 1,038
===== ===== ======
Current income tax expense (benefit):
U.S. federal.............................................. $ (34) 23 107
Various states............................................ 11 6 6
Canada.................................................... 28 8 2
International............................................. 18 11 5
----- ----- ------
Total current tax expense................................. 23 48 120
----- ----- ------
Deferred income tax expense (benefit):
U.S. federal.............................................. 56 124 152
Various states............................................ (14) (32) 33
Canada.................................................... (253) (145) 67
International............................................. (5) 10 5
----- ----- ------
Total deferred tax expense (benefit)...................... (216) (43) 257
----- ----- ------
Total income tax expense (benefit).......................... $(193) 5 377
===== ===== ======
</Table>
The taxes on the results of discontinued operations presented in the
accompanying statements of operations were all related to foreign operations.
95
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Total income tax expense (benefit) differed from the amounts computed by
applying the U.S. federal income tax rate to earnings (loss) before income taxes
as a result of the following:
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Expected income tax (benefit) based on U.S. statutory tax
rate of 35%............................................... $ (47) 10 363
Benefit from disposition of certain foreign assets.......... -- -- (46)
Financial expenses not deductible for income tax purposes... -- 12 15
Dividends received deduction................................ (5) (5) (5)
Nonconventional fuel source credits......................... (19) (19) (8)
State income taxes.......................................... 7 4 15
Taxation on foreign operations.............................. (121) 5 22
Other....................................................... (8) (2) 21
----- ---- ----
Total income tax expense (benefit).......................... $(193) 5 377
===== ==== ====
</Table>
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 2002, 2001
and 2000 are presented below:
<Table>
<Caption>
DECEMBER 31,
-------------------------
2002 2001 2000
------- ------- -----
(IN MILLIONS)
<S> <C> <C> <C>
Deferred tax assets:
Net operating loss carryforwards........................ $ 78 39 123
Minimum tax credit carryforwards........................ 164 118 85
Long-term debt.......................................... -- 6 17
Fair value of financial instruments..................... 46 7 --
Pension benefit obligation.............................. 42 11 --
Other................................................... 53 26 95
------- ------- -----
Total deferred tax assets............................... 383 207 320
------- ------- -----
Deferred tax liabilities:
Property and equipment, principally due to nontaxable
business combinations, differences in depreciation,
and the expensing of intangible drilling costs for
tax purposes......................................... (2,863) (2,189) (694)
ChevronTexaco Corporation common stock.................. (147) (213) (167)
Other................................................... -- (11) (84)
------- ------- -----
Total deferred tax liabilities.......................... (3,010) (2,413) (945)
------- ------- -----
Net deferred tax liability......................... $(2,627) (2,206) (625)
======= ======= =====
</Table>
As shown in the above table, Devon has recognized $383 million of deferred
tax assets as of December 31, 2002. Such amount consists primarily of $242
million of various carryforwards available to offset future income taxes. The
carryforwards include federal net operating loss carryforwards, the majority of
which do not begin to expire until 2008, state net operating loss carryforwards
which expire primarily between 2003 and 2016, Canadian carryforwards which
expire primarily in 2008, International carryforwards which have no expiration
and minimum tax credit carryforwards which have no expiration. The tax benefits
of carryforwards are recorded as an asset to the extent that management assesses
the
96
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
utilization of such carryforwards to be "more likely than not." When the future
utilization of some portion of the carryforwards is determined not to be "more
likely than not," a valuation allowance is provided to reduce the recorded tax
benefits from such assets.
Devon expects the tax benefits from the net operating loss carryforwards to
be utilized between 2003 and 2008. 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 tax regulations.
Significant changes in such estimates caused by variables such as future oil and
gas prices or capital expenditures could alter the timing of the eventual
utilization of such carryforwards. There can be no assurance that Devon will
generate any specific level of continuing taxable earnings. However, management
believes that Devon's future taxable income will more likely than not be
sufficient to utilize substantially all its tax carryforwards prior to their
expiration.
8. STOCKHOLDERS' EQUITY
The authorized capital stock of Devon consists of 400 million shares of
common stock, par value $.10 per share (the "Common Stock"), and 4.5 million
shares of preferred stock, par value $1.00 per share. The preferred stock may be
issued in one or more series, and the terms and rights of such stock will be
determined by the Board of Directors.
There were 16 million Exchangeable Shares issued on December 10, 1998, in
connection with the Northstar Energy Corporation combination. As of year-end
2002, 14 million of the Exchangeable Shares had been exchanged for shares of
Devon's common stock. The Exchangeable Shares have rights identical to those of
Devon's common stock and are exchangeable at any time into Devon's common stock
on a one-for-one basis.
Effective August 17, 1999, Devon issued 1.5 million shares of 6.49%
cumulative preferred stock, Series A, to holders of PennzEnergy 6.49% cumulative
preferred stock, Series A. Dividends on the preferred stock are cumulative from
the date of original issue and are payable quarterly, in cash, when declared by
the Board of Directors. The preferred stock is redeemable at the option of Devon
at any time on or after June 2, 2008, in whole or in part, at a redemption price
of $100 per share, plus accrued and unpaid dividends to the redemption date.
As discussed in Note 2, there were approximately 30 million shares of Devon
common stock issued on January 24, 2002, in connection with the Mitchell
acquisition. Also, Devon's Board of Directors has designated a certain number of
shares of the preferred stock as Series A Junior Participating Preferred Stock
(the "Series A Junior Preferred Stock") in connection with the adoption of the
shareholder rights plan described later in this note. Effective January 22,
2002, the Board voted to increase the designated shares from one million to two
million. At December 31, 2002, there were no shares of Series A Junior Preferred
Stock issued or outstanding. The Series A Junior Preferred Stock is entitled to
receive cumulative quarterly dividends per share equal to the greater of $10 or
100 times the aggregate per share amount of all dividends (other than stock
dividends) declared on Common Stock since the immediately preceding quarterly
dividend payment date or, with respect to the first payment date, since the
first issuance of Series A Junior Preferred Stock. Holders of the Series A
Junior Preferred Stock are entitled to 100 votes per share (subject to
adjustment to prevent dilution) on all matters submitted to a vote of the
stockholders. The Series A Junior Preferred Stock is neither redeemable nor
convertible. The Series A Junior Preferred Stock ranks prior to the Common Stock
but junior to all other classes of Preferred Stock.
STOCK OPTION PLANS
Devon has outstanding stock options issued to key management and
professional employees under three stock option plans adopted in 1988, 1993 and
1997 (the "1988 Plan," the "1993 Plan" and the
97
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"1997 Plan"). Options granted under the 1988 Plan and 1993 Plan remain
exercisable by the employees owning such options, but no new options will be
granted under these plans. At December 31, 2002, there were 13,000 and 309,000
options outstanding under the 1988 Plan and the 1993 Plan, respectively.
On May 21, 1997, Devon's stockholders adopted the 1997 Plan and reserved
two million shares of Common Stock for issuance thereunder. On December 9, 1998,
Devon's stockholders voted to increase the reserved number of shares to three
million. On August 17, 1999, Devon's stockholders voted to increase the reserved
number of shares to six million. On August 29, 2000, Devon's stockholders voted
to increase the reserved number of shares to 10 million.
The exercise price of stock options granted under the 1997 Plan may not be
less than the estimated fair market value of the stock at the date of grant.
Options granted are exercisable during a period established for each grant,
which period may not exceed 10 years from the date of grant. Under the 1997
Plan, the grantee must pay the exercise price in cash or in Common Stock, or a
combination thereof, at the time that the option is exercised. The 1997 Plan is
administered by a committee comprised of non-management members of the Board of
Directors. The 1997 Plan expires on April 25, 2007. As of December 31, 2002,
there were 7,477,000 options outstanding under the 1997 Plan. There were
1,237,000 options available for future grants as of December 31, 2002.
In addition to the stock options outstanding under the 1988 Plan, 1993 Plan
and 1997 Plan, there were approximately 1,327,000, 774,000, 1,314,000 and 17,000
stock options outstanding at the end of 2002 that were assumed as part of the
Mitchell acquisition, the Santa Fe Snyder merger, the PennzEnergy merger and the
Northstar combination, respectively.
A summary of the status of Devon's stock option plans as of December 31,
2000, 2001 and 2002, and changes during each of the years then ended, is
presented below.
<Table>
<Caption>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------- -------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
NUMBER EXERCISE NUMBER EXERCISE
OUTSTANDING PRICE EXERCISABLE PRICE
-------------- -------- -------------- --------
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance at December 31, 1999........... 8,554 $38.20 7,064 $39.55
===== ======
Options granted...................... 1,625 $51.43
Options exercised.................... (2,489) $33.11
Options forfeited.................... (334) $60.35
------
Balance at December 31, 2000........... 7,356 $41.84 6,025 $40.72
===== ======
Options granted...................... 2,601 $35.43
Options exercised.................... (1,505) $31.13
Options forfeited.................... (268) $62.77
------
Balance at December 31, 2001........... 8,184 $41.09 5,516 $41.93
===== ======
Options granted...................... 2,807 $45.77
Options assumed in the Mitchell
acquisition....................... 1,554 $26.82
Options exercised.................... (899) $29.33
Options forfeited.................... (415) $47.12
------
Balance at December 31, 2002........... 11,231 $41.00 6,991 $40.05
====== ===== ======
</Table>
98
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The weighted average fair values of options granted during 2002, 2001 and
2000 were $15.25, $13.17 and $28.73, respectively. The fair value of each option
grant was estimated for disclosure purposes on the date of grant using the
Black-Scholes Option Pricing Model with the following assumptions for 2002, 2001
and 2000, respectively: risk-free interest rates of 3.2%, 3.8% and 5.5%;
dividend yields of 0.4%, 0.6% and 0.4%; expected lives of five, five and five
years; and volatility of the price of the underlying common stock of 41.8%,
42.2% and 40.0%.
The following table summarizes information about Devon's stock options
which were outstanding, and those which were exercisable, as of December 31,
2002:
<Table>
<Caption>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------- -------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
NUMBER REMAINING EXERCISE NUMBER EXERCISE
RANGE OF EXERCISE PRICES OUTSTANDING LIFE PRICE EXERCISABLE PRICE
- ------------------------ -------------- ---------- -------- -------------- --------
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
$10.270 - $25.667.................. 1,157 2.70 Years $ 18.63 1,157 $18.63
$29.125 - $33.381.................. 956 6.12 Years $ 30.87 956 $30.87
$34.375 - $39.773.................. 3,281 6.74 Years $ 35.40 1,735 $35.72
$40.483 - $49.950.................. 3,566 6.99 Years $ 46.00 1,244 $45.82
$50.142 - $59.813.................. 1,772 5.88 Years $ 53.04 1,404 $53.36
$60.150 - $89.660.................. 499 4.36 Years $ 70.79 495 $70.87
------ -----
11,231 6.11 Years $ 41.00 6,991 $40.05
====== =====
</Table>
SHAREHOLDER RIGHTS PLAN
Under Devon's shareholder rights plan, stockholders have one right for each
share of Common Stock held. The rights become exercisable and separately
transferable ten business days after a) an announcement that a person has
acquired, or obtained the right to acquire, 15% or more of the voting shares
outstanding, or b) commencement of a tender or exchange offer that could result
in a person owning 15% or more of the voting shares outstanding.
Each right entitles its holder (except a holder who is the acquiring
person) to purchase either (a) 1/100 of a share of Series A Preferred Stock for
$75.00, subject to adjustment or, (b) Devon Common Stock with a value equal to
twice the exercise price of the right, subject to adjustment to prevent
dilution. In the event of certain merger or asset sale transactions with another
party or transactions which would increase the equity ownership of a shareholder
who then owned 15% or more of Devon, each Devon right will entitle its holder to
purchase securities of the merging or acquiring party with a value equal to
twice the exercise price of the right.
The rights, which have no voting power, expire on April 16, 2005. The
rights may be redeemed by Devon for $.01 per right until the rights become
exercisable.
99
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values
of Devon's financial instruments at December 31, 2002, 2001 and 2000.
<Table>
<Caption>
2002 2001 2000
------------------ ------------------ ------------------
CARRYING FAIR CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE AMOUNT VALUE
-------- ------- -------- ------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Investments................. $ 479 479 644 644 606 606
Oil and gas price hedge
agreements................ $ (144) (144) 225 225 -- (58)
Interest rate swap
agreements................ $ (5) (5) (9) (9) -- --
Electricity hedge
agreements................ $ (2) (2) (12) (12) -- --
Foreign exchange hedge
agreements................ $ (1) (1) (4) (4) -- (1)
Embedded option in
exchangeable debentures... $ (12) (12) (34) (34) -- --
Long-term debt.............. $(7,562) (8,425) (6,589) (6,699) (2,049) (2,050)
</Table>
The following methods and assumptions were used to estimate the fair values
of the financial instruments in the above table. The carrying values of cash and
cash equivalents, accounts receivable and accounts payable (including income
taxes payable and accrued expenses) included in the accompanying consolidated
balance sheets approximated fair value at December 31, 2002, 2001 and 2000.
Investments -- The fair values of investments are primarily based on quoted
market prices.
Oil and Gas Price Hedge Agreements -- The fair values of the oil and gas
price hedges are based on either (a) an internal discounted cash flow
calculation, (b) quotes obtained from the counterparty to the hedge agreement or
(c) quotes provided by brokers.
Interest Rate Swap Agreements -- The fair values of the interest rate swaps
are based on quotes obtained from the counterparty to the swap agreement.
Electricity Hedge Agreements -- The fair values of the electricity hedges
are based on an internal discounted cash flow calculation.
Foreign Exchange Hedge Agreements -- The fair values of the foreign
exchange agreements are based on either (a) an internal discounted cash flow
calculation or (b) quotes obtained from brokers.
Embedded Option in Exchangeable Debentures -- The fair values of the
embedded options are based on quotes obtained from brokers.
Long-term Debt -- The fair values of the fixed-rate long-term debt have
been estimated based on quotes obtained from brokers or by discounting the
principal and interest payments at rates available for debt of similar terms and
maturity. The fair values of the floating-rate long-term debt are estimated to
approximate the carrying amounts due to the fact that the interest rates paid on
such debt are generally set for periods of three months or less.
Devon's total hedged positions as of January 31, 2003 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 natural gas production in 2003. These swaps will result in a
fixed price of $3.23 per Mcf on 97,148 Mcf per day of
100
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
domestic production during 2003. Where necessary, the prices related to these
swaps 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 2003 and 2004 oil and natural gas production.
The following tables include information on these collars. 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 oil or 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 various collars.
OIL PRODUCTION
<Table>
<Caption>
WEIGHTED AVERAGE
-----------------
FLOOR CEILING
PRICE PRICE
PER PER PER PER
YEAR BBLS/DAY BBL BBL
- ---- -------- ------- -------
<S> <C> <C> <C>
2003...................................................... 53,537 $22.26 $28.14
2004...................................................... 4,000 $20.00 $27.00
</Table>
GAS PRODUCTION
<Table>
<Caption>
WEIGHTED AVERAGE
-----------------------
FLOOR PRICE CEILING
PER PRICE PER
YEAR MMBTU/DAY PER MMBTU PER MMBTU
- ---- --------- ----------- ---------
<S> <C> <C> <C>
2003.............................................. 655,096 $3.34 $5.11
2004.............................................. 130,000 $3.47 $6.44
</Table>
INTEREST RATE SWAPS
Devon assumed certain interest rate swaps as a result of the Anderson
acquisition. Under these interest rate swaps, Devon has swapped a floating rate
for a fixed rate. Under such swaps, Devon will record a fixed rate of 6.3% on
$98 million of debt in 2003, 6.4% on $79 million of debt in 2004 through
101
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
2006 and 6.3% on $24 million of debt in 2007. The amount of gains or losses
realized from such swaps are included as increases or decreases to interest
expense.
Devon has also entered into an interest rate swap on its $125 million 8.05%
senior notes due in 2004 to swap a fixed interest rate for a variable interest
rate. The variable interest rate on this instrument is based on LIBOR plus a
margin of 336 basis points.
FOREIGN CURRENCY EXCHANGE RATE SWAPS
Devon assumed certain foreign currency exchange rate swaps in the Anderson
acquisition. These swaps require Devon to sell $12 million at average
Canadian-to-U.S. exchange rates of $0.676, and buy the same amount of dollars at
the floating exchange rate, in 2003.
10. RETIREMENT PLANS
Devon has non-contributory defined benefit retirement plans (the "Basic
Plans") which include U.S. and Canadian employees meeting certain age and
service requirements. The benefits are based on the employee's years of service
and compensation. During 2002, Devon established a funding policy regarding the
Basic Plans such that it would contribute the amount of funds necessary so that
the Basic Plans' assets would be equal to the related accumulated benefit
obligation by the end of 2004. As of December 31, 2002, the Basic Plans'
accumulated benefit obligation totaled $363 million, which was $82 million more
than the related assets. Devon's intentions are to fund this deficit over the
two-year period ending December 31, 2004. The actual amount of contributions
required during this period will depend on investment returns from the plan
assets during the same period.
Devon also has separate defined benefit retirement plans (the
"Supplementary Plans") which are non-contributory and include only certain
employees whose benefits under the Basic Plans are limited by income tax
regulations. The Supplementary Plans' benefits are based on the employee's years
of service and compensation. Devon's funding policy for the Supplementary Plans
is to fund the benefits as they become payable. Rights to amend or terminate the
Supplementary Plans are retained by Devon.
Devon has defined benefit postretirement plans, which are unfunded, and
cover substantially all employees. The plans provide medical and, in some cases,
life insurance benefits and are, depending on the type of plan, either
contributory or non-contributory. The accounting for the health care plan
anticipates future cost-sharing changes that are consistent with Devon's
expressed intent to increase, where possible, contributions from future
retirees.
102
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the plans' benefit obligations, plan assets,
reconciliation of funded status, amounts recognized in the consolidated balance
sheets and the actuarial assumptions used as of December 31, 2002, 2001 and
2000.
<Table>
<Caption>
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------ ---------------------
2002 2001 2000 2002 2001 2000
---- ---- ---- ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation at beginning of
year.................................. $210 165 156 33 32 38
Service cost............................. 9 5 7 1 -- 1
Interest cost............................ 28 13 11 4 2 2
Participant contributions................ -- -- -- 1 1 --
Amendments............................... -- 5 4 -- (1) (2)
Mergers and acquisitions................. 208 16 -- 30 -- --
Special termination benefits............. -- 3 -- -- -- --
Settlement payments...................... (15) (4) -- -- -- --
Curtailment loss (gain).................. 2 (1) (3) -- -- --
Actuarial loss (gain).................... 42 17 (3) 6 4 (3)
Benefits paid............................ (24) (9) (7) (7) (5) (4)
---- ---- ---- ---- ---- ----
Benefit obligation at end of year........ 460 210 165 68 33 32
---- ---- ---- ---- ---- ----
Change in plan assets:
Fair value of plan assets at beginning of
year.................................. 156 155 158 -- -- --
Actual return on plan assets............. (47) (9) 3 -- -- --
Mergers and acquisitions................. 145 17 -- -- -- --
Employer contributions................... 66 6 1 6 4 4
Participant contributions................ -- -- -- 1 1 --
Settlement payments...................... (15) (4) -- -- -- --
Administrative expenses.................. -- -- -- -- -- --
Benefits paid............................ (24) (9) (7) (7) (5) (4)
---- ---- ---- ---- ---- ----
Fair value of plan assets at end of
year.................................. 281 156 155 -- -- --
---- ---- ---- ---- ---- ----
Funded status.............................. (179) (54) (10) (68) (33) (32)
Unrecognized net actuarial (gain) loss..... 152 35 10 8 2 (2)
Unrecognized prior service cost............ 5 6 1 (1) (1) (1)
Unrecognized net transition (asset)
obligation............................... -- -- (6) -- -- 1
---- ---- ---- ---- ---- ----
Net amount recognized...................... $(22) (13) (5) (61) (32) (34)
==== ==== ==== ==== ==== ====
The net amounts recognized in the
consolidated balance sheets consist of:
(Accrued) prepaid benefit cost........... $(22) (13) (5) (61) (32) (34)
Additional minimum liability............. (118) (33) (1) -- -- --
Intangible asset......................... 5 5 1 -- -- --
Accumulated other comprehensive loss..... 113 28 -- -- -- --
---- ---- ---- ---- ---- ----
Net amount recognized.................... $(22) (13) (5) (61) (32) (34)
==== ==== ==== ==== ==== ====
</Table>
103
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------ ---------------------
2002 2001 2000 2002 2001 2000
---- ---- ---- ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Assumptions:
Discount rate............................ 6.72% 7.10% 7.65% 6.75% 7.15% 7.65%
Expected return on plan assets........... 8.27% 8.27% 8.50% N/A N/A N/A
Rate of compensation increase............ 4.88% 4.88% 5.00% 5.00% 5.00% 5.00%
</Table>
As indicated in the prior table, Devon's defined benefit plans had a
combined underfunded status of $179 million as of December 31, 2002. Of this
$179 million total, $75 million is attributable to the Supplementary Plans which
have no plan assets. However, certain trusts have been established to assist
Devon in funding the benefit obligations of such Supplementary Plans. At
December 31, 2002, these trusts had investments with a market value of
approximately $53 million. This total is included in noncurrent other assets in
the accompanying consolidated balance sheets.
The accumulated benefit obligation was in excess of plan assets for each of
the defined benefit pension plans as of December 31, 2002.
Net periodic benefit cost included the following components:
<Table>
<Caption>
OTHER POSTRETIREMENT
PENSION BENEFITS BENEFITS
------------------ ----------------------
2002 2001 2000 2002 2001 2000
---- ---- ---- ----- ------ -----
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Service cost................................. $ 9 5 7 1 -- 1
Interest cost................................ 28 13 11 4 2 2
Expected return on plan assets............... (24) (13) (13) -- -- --
Amortization of prior service cost........... 1 1 -- -- -- --
Recognized net actuarial (gain) loss......... 2 1 -- -- -- --
---- ---- ---- -- ----- --
Net periodic benefit cost.................... $ 16 7 5 5 2 3
==== ==== ==== == ===== ==
</Table>
For measurement purposes, a 10% annual rate of increase in the per capita
cost of covered health care benefits was assumed in 2002. The rate was assumed
to decrease on a pro-rata basis annually to 5% in the year 2008 and remain at
that level thereafter. Assumed health care cost trend rates have a significant
effect on the amounts reported for the health care plan. A one percentage-point
change in assumed health care cost trend rates would have the following effects:
<Table>
<Caption>
ONE-PERCENTAGE ONE-PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(IN MILLIONS)
<S> <C> <C>
Effect on total of service and interest cost components
for 2002............................................... $-- $--
Effect on year-end 2002 postretirement benefit
obligation............................................. $ 3 $(4)
</Table>
Devon has incurred certain postemployment benefits to former or inactive
employees who are not retirees. These benefits include salary continuance,
severance and disability health care and life insurance which are accounted for
under SFAS No. 112, Employer's Accounting for Postemployment Benefits. The
accrued postemployment benefit liability was approximately $6 million, $7
million and $13 million at the end of 2002, 2001 and 2000, respectively.
Devon has a 401(k) Incentive Savings Plan which covers all domestic
employees. At its discretion, Devon may match a certain percentage of the
employees' contributions to the plan. The matching percentage is determined
annually by the Board of Directors. Devon's matching contributions to the plan
104
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
were $8 million, $5 million and $5 million for the years ended December 31,
2002, 2001 and 2000, respectively.
Devon has defined contribution pension plans for its Canadian employees.
Devon makes a contribution to each employee which is based upon the employee's
base compensation and classification. Such contributions are subject to maximum
amounts allowed under the Income Tax Act (Canada).
Devon also has a savings plan for its Canadian employees. Under the savings
plan, Devon contributes a base percentage amount to all employees and the
employee may elect to contribute an additional percentage amount (up to a
maximum amount) which is matched by additional Devon contributions.
During the years 2002, 2001 and 2000, Devon's combined contributions to the
Canadian defined contribution plan and the Canadian savings plan were $8
million, $3 million and $2 million, respectively.
11. COMMITMENTS AND CONTINGENCIES
Devon is party to various legal actions arising in the normal course of
business. Matters that are probable of unfavorable outcome to Devon and which
can be reasonably estimated are accrued. Such accruals are based on information
known about the matters, Devon's estimates of the outcomes of such matters and
its experience in contesting, litigating and settling similar matters. None of
the actions are believed by management to involve future amounts that would be
material 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 past mergers 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 December 31, 2002, Devon's consolidated balance sheet included $8 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) Devon's participation in
consent decrees with both other PRPs and the Environmental Protection Agency,
which provide for performing the scope of work required for remediation and
contain covenants not to sue as protection to the PRPs, (ii) participation in
groups as a de minimis PRP, and (iii) the availability of other defenses to
liability. 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
105
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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.
Devon is a defendant in certain private royalty owner litigation filed in
Wyoming regarding deductibility of certain post production costs from royalties
payable by Devon. The plaintiffs in these lawsuits propose to expand them into
county or state-wide class actions relating specifically to transportation and
related costs associated with Devon's Wyoming gas production. A significant
portion of such production is, or will be, transported through facilities owned
by Thunder Creek Gas Services, L.L.C., of which Devon owns a 75% interest. Devon
believes that it has acted reasonably and paid royalties in good faith and in
accordance with its obligations under its oil and gas leases and applicable law,
and Devon does not believe that it is subject to material exposure in
association with this litigation.
OTHER MATTERS
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.
OPERATING LEASES
The following is a schedule by year of future minimum rental payments
required under operating leases that have initial or remaining noncancelable
lease terms in excess of one year as of December 31, 2002:
<Table>
<Caption>
YEAR ENDING DECEMBER 31,
- ------------------------ (IN MILLIONS)
<S> <C>
2003........................................................ $ 30
2004........................................................ 33
2005........................................................ 28
2006........................................................ 24
2007........................................................ 20
Thereafter.................................................. 86
----
Total minimum lease payments required.................. $221
====
</Table>
106
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Total rental expense for all operating leases is as follows for the years
ended December 31:
<Table>
<Caption>
(IN MILLIONS)
<S> <C>
2002........................................................ $37
2001........................................................ $17
2000........................................................ $19
</Table>
The 2002 rent expense includes $13 million for the abandonment of certain
office space obtained in the Santa Fe Snyder merger.
12. 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, may not exceed a calculated
"ceiling." The ceiling limitation is the discounted estimated after-tax future
net revenues from proved oil and gas properties plus the cost of properties not
subject to amortization. The ceiling is determined separately by country. In
calculating future net revenues, current prices and costs are generally held
constant indefinitely. The net book value, less deferred tax liabilities, is
compared to the ceiling on a quarterly and annual basis. Any excess of the net
book value, less related deferred taxes, 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.
During 2002 and 2001, Devon reduced the carrying value of its oil and gas
properties by $651 and $883 million, respectively, due to the full cost ceiling
limitations. The after-tax effect of these reductions in 2002 and 2001 were $371
million and $533 million, respectively. The following table summarizes these
reductions by country.
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------------
2002 2001
-------------- --------------
NET OF NET OF
GROSS TAXES GROSS TAXES
----- ------ ----- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
United States........................................... $ -- -- 449 281
Canada.................................................. 651 371 434 252
---- --- --- ---
Total.............................................. $651 371 883 533
==== === === ===
</Table>
The 2002 Canadian reduction was primarily the result of lower prices. 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 recorded values of oil and gas properties added from the Anderson
acquisition in 2001 were based on expected future oil and gas prices that were
higher than the June 30, 2002, prices used to calculate the Canadian ceiling.
The 2001 domestic and Canadian reductions were also primarily the result of
lower prices. The oil and gas properties added from the Anderson acquisition and
other smaller acquisitions in 2001 were recorded at fair values that were based
on expected future oil and gas prices higher than the December 31, 2001 prices
used to calculate the ceiling.
Additionally, during 2001, Devon elected to abandon 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.
107
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accordingly, Devon recorded an $96 million charge associated with the impairment
of these properties. The after-tax effect of this reduction was $78 million.
The provisions of SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets, which Devon was required to adopt effective January 1,
2002, are only required to be applied prospectively. As a result, these
impairment charges have not been reclassified as part of the Discontinued
Operations on the consolidated statements of operations.
13. SEGMENT INFORMATION
Devon manages its business by country. As such, Devon identifies its
segments based on geographic areas. Devon has three reportable 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 activities. Certain information
regarding such activities for each segment is included in Note 14.
Following is certain financial information regarding Devon's segments for
2002, 2001 and 2000. The revenues reported are all from external customers.
<Table>
<Caption>
U.S. CANADA INTERNATIONAL TOTAL
------ ------ ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 2002:
Current assets................................... $ 603 366 95 1,064
Property and equipment, net of accumulated
depreciation, depletion and amortization....... 6,838 3,497 517 10,852
Goodwill, net of amortization.................... 1,565 1,921 69 3,555
Other assets..................................... 723 31 -- 754
------ ----- --- ------
Total assets................................ $9,729 5,815 681 16,225
====== ===== === ======
Current liabilities.............................. $ 626 344 72 1,042
Long-term debt................................... 3,545 4,017 -- 7,562
Deferred tax liabilities......................... 1,520 1,062 45 2,627
Other liabilities................................ 333 7 1 341
Stockholders' equity............................. 3,705 385 563 4,653
------ ----- --- ------
Total liabilities and stockholders'
equity.................................... $9,729 5,815 681 16,225
====== ===== === ======
</Table>
108
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
U.S. CANADA INTERNATIONAL TOTAL
------ ------ ------------- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2002:
Revenues:
Oil sales............................................... $ 524 331 54 909
Gas sales............................................... 1,403 730 -- 2,133
Natural gas liquids sales............................... 192 83 -- 275
Marketing and midstream revenues........................ 985 14 -- 999
------ ----- -- -----
Total revenues....................................... 3,104 1,158 54 4,316
------ ----- -- -----
Operating Costs And Expenses:
Lease operating expenses................................ 354 255 12 621
Transportation costs.................................... 99 55 -- 154
Production taxes........................................ 104 7 -- 111
Marketing and midstream operating costs and expenses.... 800 8 -- 808
Depreciation, depletion and amortization of property and
equipment............................................ 834 371 6 1,211
General and administrative expenses..................... 166 40 13 219
Reduction in carrying value of oil and gas properties... -- 651 -- 651
------ ----- -- -----
Total operating costs and expenses................... 2,357 1,387 31 3,775
------ ----- -- -----
Earnings (loss) from operations........................... 747 (229) 23 541
Other Income (Expenses):
Interest expense........................................ (235) (295) (3) (533)
Effects of changes in foreign currency exchange rates... -- 1 -- 1
Change in fair value of financial instruments........... 31 (3) -- 28
Impairment of ChevronTexaco Corporation common stock.... (205) -- -- (205)
Other income............................................ 16 11 7 34
------ ----- -- -----
Net other income (expenses).......................... (393) (286) 4 (675)
------ ----- -- -----
Earnings (loss) from continuing operations before income
taxes................................................... 354 (515) 27 (134)
Income Tax Expense (Benefit):
Current................................................. (23) 28 18 23
Deferred................................................ 42 (253) (5) (216)
------ ----- -- -----
Total income tax expense (benefit)................... 19 (225) 13 (193)
------ ----- -- -----
Earnings (loss) from continuing operations................ 335 (290) 14 59
Discontinued Operations:
Results of discontinued operations before income
taxes................................................ -- -- 54 54
Income tax expense...................................... -- -- 9 9
------ ----- -- -----
Net results of discontinued operations.................. -- -- 45 45
------ ----- -- -----
Net earnings (loss)....................................... $ 335 (290) 59 104
====== ===== == =====
Capital expenditures...................................... $2,797 532 97 3,426
====== ===== == =====
</Table>
109
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
U.S. CANADA INTERNATIONAL TOTAL
------ ------ ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 2001:
Current assets.......................................... $ 661 192 501 1,354
Property and equipment, net of accumulated depreciation,
depletion and amortization............................ 4,051 4,248 463 8,762
Goodwill, net of amortization........................... 209 1,928 69 2,206
Other assets............................................ 826 33 3 862
------ ----- ----- ------
Total assets....................................... $5,747 6,401 1,036 13,184
====== ===== ===== ======
Current liabilities..................................... $ 407 367 145 919
Long-term debt.......................................... 1,987 4,602 -- 6,589
Deferred tax liabilities................................ 775 1,316 58 2,149
Other liabilities....................................... 224 20 24 268
Stockholders' equity.................................... 2,354 96 809 3,259
------ ----- ----- ------
Total liabilities and stockholders' equity......... $5,747 6,401 1,036 13,184
====== ===== ===== ======
</Table>
110
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
U.S. CANADA INTERNATIONAL TOTAL
------ ------ ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2001:
Revenues:
Oil sales............................................. $ 586 146 52 784
Gas sales............................................. 1,571 307 -- 1,878
Natural gas liquids sales............................. 103 28 -- 131
Marketing and midstream revenues...................... 64 7 -- 71
------ ----- ----- ------
Total revenues................................ 2,324 488 52 2,864
------ ----- ----- ------
Operating Costs And Expenses:
Lease operating expenses.............................. 340 110 17 467
Transportation costs.................................. 59 24 -- 83
Production taxes...................................... 113 3 -- 116
Marketing and midstream operating costs and
expenses........................................... 43 4 -- 47
Depreciation, depletion and amortization of property
and equipment...................................... 647 166 18 831
Amortization of goodwill.............................. 34 -- -- 34
General and administrative expenses................... 98 15 1 114
Expenses related to mergers........................... -- 1 -- 1
Reduction in carrying value of oil and gas
properties......................................... 449 434 96 979
------ ----- ----- ------
Total operating costs and expenses............... 1,783 757 132 2,672
------ ----- ----- ------
Earnings (loss) from operations......................... 541 (269) (80) 192
Other Income (Expenses):
Interest expense...................................... (139) (81) -- (220)
Effects of changes in foreign currency exchange
rates.............................................. -- (11) -- (11)
Change in fair value of financial instruments......... (1) (1) -- (2)
Other income.......................................... 57 5 7 69
------ ----- ----- ------
Net other income (expenses)................... (83) (88) 7 (164)
------ ----- ----- ------
Earnings (loss) from continuing operations before income
taxes and cumulative effect of change in accounting
principle............................................. $ 458 $(357) $ (73) $ 28
Income Tax Expense (Benefit):
Current............................................... 29 8 11 48
Deferred.............................................. 92 (145) 10 (43)
------ ----- ----- ------
Total income tax expense (benefit)............ 121 (137) 21 5
------ ----- ----- ------
Earnings (loss) from continuing operations before
cumulative effect of change in accounting principle... 337 (220) (94) 23
Discontinued Operations:
Results of discontinued operations before income
taxes.............................................. -- -- 56 56
Income tax expense.................................... -- -- 25 25
------ ----- ----- ------
Net results of discontinued operations................ -- -- 31 31
------ ----- ----- ------
Earnings (loss) before cumulative effect of change in
accounting principle.................................. 337 (220) (63) 54
Cumulative effect of change in accounting principle..... 49 -- -- 49
------ ----- ----- ------
Net earnings (loss)..................................... $ 386 (220) (63) 103
====== ===== ===== ======
Capital expenditures.................................... $1,356 3,774 105 5,235
====== ===== ===== ======
</Table>
111
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
U.S. CANADA INTERNATIONAL TOTAL
------ ------ ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
AS OF DECEMBER 31, 2000:
Current assets.......................................... $ 645 79 104 828
Property and equipment, net of accumulated depreciation,
depletion and amortization............................ 3,640 586 436 4,662
Goodwill, net of amortization........................... 244 -- 45 289
Assets of discontinued operations....................... -- -- 361 361
Other assets............................................ 720 -- -- 720
------ ----- ----- ------
Total assets..................................... $5,249 665 946 6,860
====== ===== ===== ======
Current liabilities..................................... $ 449 74 54 577
Long-term debt.......................................... 1,902 147 -- 2,049
Deferred tax liabilities................................ 537 69 28 634
Liabilities of discontinued operations.................. -- -- 51 51
Other liabilities....................................... 259 1 12 272
Stockholders' equity.................................... 2,102 374 801 3,277
------ ----- ----- ------
Total liabilities and stockholders' equity....... $5,249 665 946 6,860
====== ===== ===== ======
</Table>
112
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
U.S. CANADA INTERNATIONAL TOTAL
------ ------ ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 2000:
Revenues:
Oil sales............................................. $ 727 116 63 906
Gas sales............................................. 1,305 169 -- 1,474
Natural gas liquids sales............................. 136 18 -- 154
Marketing and midstream revenues...................... 47 6 -- 53
------ ----- ----- ------
Total revenues................................... 2,215 309 63 2,587
------ ----- ----- ------
Operating Costs And Expenses:
Lease operating expenses.............................. 319 52 17 388
Transportation costs.................................. 42 11 -- 53
Production taxes...................................... 102 1 -- 103
Marketing and midstream operating costs and
expenses........................................... 25 3 -- 28
Depreciation, depletion and amortization of property
and equipment...................................... 565 65 32 662
Amortization of goodwill.............................. 41 -- -- 41
General and administrative expenses................... 81 10 5 96
Expenses related to mergers........................... 60 -- -- 60
------ ----- ----- ------
Total operating costs and expenses................. 1,235 142 54 1,431
------ ----- ----- ------
Earnings from operations.............................. 980 167 9 1,156
Other Income (Expenses):
Interest expense...................................... (144) (10) (1) (155)
Effects of changes in foreign currency exchange
rates.............................................. -- (3) -- (3)
Other income.......................................... 36 2 2 40
------ ----- ----- ------
Net other income (expenses)........................ (108) (11) 1 (118)
------ ----- ----- ------
Earnings from continuing operations before income
taxes................................................. 872 156 10 1,038
Income Tax Expense:
Current............................................... 113 2 5 120
Deferred.............................................. 185 67 5 257
------ ----- ----- ------
Total income tax expense......................... 298 69 10 377
------ ----- ----- ------
Earnings from continuing operations..................... 574 87 -- 661
Discontinued Operations:
Results of discontinued operations before income
taxes.............................................. -- -- 104 104
Income tax expense.................................... -- -- 35 35
------ ----- ----- ------
Net results of discontinued operations................ -- -- 69 69
------ ----- ----- ------
Net earnings............................................ $ 574 87 69 730
====== ===== ===== ======
Capital expenditures.................................... $ 893 203 52 1,148
====== ===== ===== ======
</Table>
113
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)
The following supplemental unaudited information regarding the oil and gas
activities of Devon is presented pursuant to the disclosure requirements
promulgated by the Securities and Exchange Commission and SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities."
COSTS INCURRED
The following tables reflect the costs incurred in oil and gas property
acquisition, exploration, and development activities:
<Table>
<Caption>
TOTAL
------------------------
YEAR ENDED DECEMBER 31,
------------------------
2002 2001 2000
------- ------ -----
(IN MILLIONS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes................... $1,538 2,971 247
Deferred income taxes..................................... -- 84 --
------ ----- ---
Total proved, including deferred income taxes............. $1,538 3,055 247
====== ===== ===
Unproved, excluding deferred income taxes:
Business combinations.................................. $ 639 1,433 --
Other acquisitions..................................... 64 183 54
Deferred income taxes..................................... -- 27 --
------ ----- ---
Total unproved, including deferred income taxes........... $ 703 1,643 54
====== ===== ===
Exploration costs........................................... $ 383 337 197
Development costs........................................... $1,140 916 562
</Table>
<Table>
<Caption>
DOMESTIC
--------------------
YEAR ENDED
DECEMBER 31,
--------------------
2002 2001 2000
------ ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes................... $1,536 292 177
Deferred income taxes..................................... -- 79 --
------ --- ---
Total proved, including deferred income taxes............. $1,536 371 177
====== === ===
Unproved, excluding deferred income taxes:
Business combinations.................................. $ 639 -- --
Other acquisitions..................................... 27 158 35
Deferred income taxes..................................... -- 27 --
------ --- ---
Total unproved, including deferred income taxes........... $ 666 185 35
====== === ===
Exploration costs........................................... $ 161 166 117
Development costs........................................... $ 808 726 466
</Table>
114
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
CANADA
-------------------
YEAR ENDED
DECEMBER 31,
-------------------
2002 2001 2000
---- ----- ----
(IN MILLIONS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes................... $ 2 2,621 70
Deferred income taxes..................................... -- 5 --
---- ----- --
Total proved, including deferred income taxes............. $ 2 2,626 70
==== ===== ==
Unproved, excluding deferred income taxes:
Business combinations.................................. $ -- 1,433 --
Other acquisitions..................................... 28 24 17
Deferred income taxes..................................... -- -- --
---- ----- --
Total unproved, including deferred income taxes........... $ 28 1,457 17
==== ===== ==
Exploration costs........................................... $207 126 55
Development costs........................................... $299 168 57
</Table>
<Table>
<Caption>
INTERNATIONAL
------------------
YEAR ENDED
DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN MILLIONS)
<S> <C> <C> <C>
Property acquisition costs:
Proved, excluding deferred income taxes................... $-- 58 --
Deferred income taxes..................................... -- -- --
--- -- --
Total proved, including deferred income taxes............. $-- 58 --
=== == ==
Unproved, excluding deferred income taxes:
Business combinations.................................. $-- -- --
Other acquisitions..................................... 9 1 2
Deferred income taxes..................................... -- -- --
--- -- --
Total unproved, including deferred income taxes........... $ 9 1 2
=== == ==
Exploration costs........................................... $15 45 25
Development costs........................................... $33 22 39
</Table>
The preceding Total and International cost incurred tables exclude $16
million, $85 million and $135 million in 2002, 2001 and 2000, respectively,
related to discontinued operations.
Pursuant to the full cost method of accounting, Devon capitalizes certain
of its general and administrative expenses which are related to property
acquisition, exploration and development activities. Such capitalized expenses,
which are included in the costs shown in the preceding tables, were $97 million,
$77 million and $62 million in the years 2002, 2001 and 2000, respectively.
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The following tables include revenues and expenses associated directly with
Devon's oil and gas producing activities, including general and administrative
expenses directly related to such producing
115
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
activities. They do not include any allocation of Devon's interest costs or
general corporate overhead and, therefore, are not necessarily indicative of the
contribution to net earnings of Devon's oil and gas operations. Income tax
expense has been calculated by applying statutory income tax rates to oil, gas
and NGL sales after deducting costs, including depreciation, depletion and
amortization and after giving effect to permanent differences.
<Table>
<Caption>
TOTAL
--------------------------
YEAR ENDED DECEMBER 31,
--------------------------
2002 2001 2000
-------- ------ ------
(IN MILLIONS, EXCEPT PER
EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales...................... $ 3,317 2,793 2,534
Production and operating expenses........................... (886) (666) (544)
Depreciation, depletion and amortization.................... (1,106) (793) (632)
Amortization of goodwill.................................... -- (34) (41)
General and administrative expenses directly related to oil
and gas producing activities.............................. (29) (17) (14)
Reduction of carrying value of oil and gas properties....... (651) (979) --
Income tax expense.......................................... (234) (126) (533)
------- ----- -----
Results of operations for oil and gas producing
activities................................................ $ 411 178 770
======= ===== =====
Depreciation, depletion and amortization per equivalent
barrel of production...................................... $ 5.88 6.30 5.58
======= ===== =====
</Table>
<Table>
<Caption>
DOMESTIC
----------------------------
YEAR ENDED DECEMBER 31,
----------------------------
2002 2001 2000
-------- ------- -------
(IN MILLIONS, EXCEPT PER
EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales...................... $2,119 2,260 2,168
Production and operating expenses........................... (557) (512) (463)
Depreciation, depletion and amortization.................... (737) (615) (541)
Amortization of goodwill.................................... -- (34) (41)
General and administrative expenses directly related to oil
and gas producing activities.............................. (14) (9) (10)
Reduction of carrying value of oil and gas properties....... -- (449) --
Income tax (expense) benefit................................ (295) (263) (442)
------ ----- -----
Results of operations for oil and gas producing
activities................................................ $ 516 378 671
====== ===== =====
Depreciation, depletion and amortization per equivalent
barrel of production...................................... $ 6.22 6.48 5.73
====== ===== =====
</Table>
116
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
CANADA
--------------------------
YEAR ENDED DECEMBER 31,
--------------------------
2002 2001 2000
-------- ------ ------
(IN MILLIONS, EXCEPT PER
EQUIVALENT BARREL AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales...................... $1,144 481 303
Production and operating expenses........................... (317) (137) (64)
Depreciation, depletion and amortization.................... (364) (164) (64)
General and administrative expenses directly related to oil
and gas producing activities.............................. (14) (6) (3)
Reduction of carrying value of oil and gas properties....... (651) (434) --
Income tax benefit (expense)................................ 74 102 (79)
------ ---- ----
Results of operations for oil and gas producing
activities................................................ $ (128) (158) 93
====== ==== ====
Depreciation, depletion and amortization per equivalent
barrel of production...................................... $ 5.39 5.74 4.05
====== ==== ====
</Table>
<Table>
<Caption>
INTERNATIONAL
-------------------------
YEAR ENDED
DECEMBER 31,
-------------------------
2002 2001 2000
------- ------ ------
(IN MILLIONS, EXCEPT PER
EQUIVALENT BARREL
AMOUNTS)
<S> <C> <C> <C>
Oil, gas and natural gas liquids sales...................... $ 54 52 63
Production and operating expenses........................... (12) (17) (17)
Depreciation, depletion and amortization.................... (5) (14) (27)
General and administrative expenses directly related to oil
and gas producing activities.............................. (1) (2) (1)
Reduction of carrying value of oil and gas properties....... -- (96) --
Income tax benefit (expense)................................ (13) 35 (12)
----- ---- ----
Results of operations for oil and gas producing
activities................................................ $ 23 (42) 6
===== ==== ====
Depreciation, depletion and amortization per equivalent
barrel of production...................................... $2.40 6.20 9.04
===== ==== ====
</Table>
The preceding Total and International results of oil and gas producing
activities tables exclude $19 million, $28 million and $66 million in 2002, 2001
and 2000, respectively, related to discontinued operations.
QUANTITIES OF OIL AND GAS RESERVES
Set forth below is a summary of the reserves which were evaluated by
independent petroleum consultants for each of the years ended 2002, 2001 and
2000.
<Table>
<Caption>
2002 2001 2000
------------------- ------------------- -------------------
ESTIMATED AUDITED ESTIMATED AUDITED ESTIMATED AUDITED
--------- ------- --------- ------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
Domestic.............................. 12% 61% 67% 9% 80% 17%
Canada................................ 31% --% 43% --% 100% --%
International......................... 100% --% 100% --% 100% --%
</Table>
117
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Estimated reserves are those quantities of reserves which were estimated by
an independent petroleum consultant. Audited reserves are those quantities of
revenues which were estimated by Devon employees and audited by an independent
petroleum consultant.
The domestic reserves were evaluated by the independent petroleum
consultants of LaRoche Petroleum Consultants, Ltd. and Ryder Scott Company, L.P.
in each of the years presented. The Canadian reserves were evaluated by the
independent petroleum consultants of AJM Petroleum Consultants in 2002; Paddock
Lindstrom & Associates and Gilbert Laustsen Jung Associates, Ltd. in 2001; and
Paddock Lindstrom & Associates in 2000. The International reserves were
evaluated by the independent petroleum consultants of Ryder Scott Company
Petroleum Consultants in each of the years presented.
Set forth below is a summary of the changes in the net quantities of crude
oil, natural gas and natural gas liquids reserves for each of the three years
ended December 31, 2002.
<Table>
<Caption>
TOTAL
-------------------------------------
Natural
Gas
Oil Gas Liquids Total
(MMBbls) (Bcf) (MMBbls) (MMBoe)
-------- ----- -------- -------
<S> <C> <C> <C> <C>
Proved reserves as of December 31, 1999.............. 439 2,785 55 958
Revisions of estimates.......................... (3) 95 4 17
Extensions and discoveries...................... 31 569 6 132
Purchase of reserves............................ 24 80 -- 37
Production...................................... (37) (417) (7) (113)
Sale of reserves................................ (48) (67) (8) (68)
--- ----- --- -----
Proved reserves as of December 31, 2000.............. 406 3,045 50 963
Revisions of estimates.......................... (14) (284) 7 (54)
Extensions and discoveries...................... 17 499 7 107
Purchase of reserves............................ 166 2,267 52 596
Production...................................... (36) (489) (8) (126)
Sale of reserves................................ (12) (14) -- (14)
--- ----- --- -----
Proved reserves as of December 31, 2001.............. 527 5,024 108 1,472
Revisions of estimates.......................... (10) (81) -- (23)
Extensions and discoveries...................... 36 570 11 142
Purchase of reserves............................ 13 1,723 105 405
Production...................................... (42) (761) (19) (188)
Sale of reserves................................ (80) (639) (13) (199)
--- ----- --- -----
Proved reserves as of December 31, 2002.............. 444 5,836 192 1,609
=== ===== === =====
Proved developed reserves as of:
December 31, 1999............................... 264 2,465 52 728
December 31, 2000............................... 232 2,595 46 711
December 31, 2001............................... 298 3,911 88 1,038
December 31, 2002............................... 260 4,618 150 1,180
</Table>
118
<PAGE>
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<Table>
<Caption>
DOMESTIC
-------------------------------------
Natural
Gas
Oil Gas Liquids Total
(MMBbls) (Bcf) (MMBbls) (MMBoe)
-------- ----- -------- -------
<S> <C> <C> <C> <C>
Proved reserves as of December 31, 1999.............. 249 2,275 51 679
Revisions of estimates............................. (3) 101 4 18
Extensions and discoveries......................... 21 504 5 110
Purchase of reserves............................... 21 53 -- 30
Production......................................... (29) (355) (6) (94)
Sale of reserves................................... (33) (57) (8) (51)
--- ----- --- ----
Proved reserves as of December 31, 2000.............. 226 2,521 46 692
Revisions of estimates............................. (25) (262) 7 (62)
Extensions and discoveries......................... 12 360 5 77
Purchase of reserves............................... 15 170 -- 43
Production......................................... (26) (376) (6) (95)
Sale of reserves................................... (11) (14) -- (13)
--- ----- --- ----
Proved reserves as of December 31, 2001........