Devon Energy Annual Report 2002

FY2002 Annual Report · Devon Energy

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2002 Annual Report

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C O N T E N T S

4 Letter to Shareholders

Chairman, President and CEO Larry
Nichols discusses an outstanding year and
the firm foundation that will support
Devon’s future.

7 Five-Year Highlights and Comparisons

10 Executive Q&A

Members of Devon’s senior management
team respond to investor questions.

11 Corporate Governance

14 Exploration and Production Portfolio
Devon is one of North America’s largest
producers of oil and gas and has a
broad portfolio of North American and
international growth opportunities.

21 Environmental, Health and Safety

22 Operating Statistics by Area
and 11-Year Property Data

24 Key Property Highlights

Devon provides brief profiles and activities on
its top oil and gas properties in a compact
foldout format.

29 Financial Statements and
Management’s Discussion
and Analysis

101 Biographies of Directors

and Senior Vice Presidents

104 Glossary of Terms

105 Common Stock Trading Data and

Investor Information

is engaged in oil and gas

Devon Energy Corporation
exploration, production and property acquisitions. Devon
ranks among the top-five U.S.-based independent oil and
gas producers and is one of the largest independent
processors of natural gas and natural gas liquids in North
America. The company also has operations in selected
international areas. Devon is included in the S&P 500 Index
and its common shares trade on the American Stock
Exchange under the ticker symbol DVN.

Devon’s primary goal is to build value per share by:

• Exploring for undiscovered oil and gas reserves,
• Purchasing and exploiting producing oil and gas

properties,

• Enhancing the value of our production through

marketing and midstream activities,

• Optimizing production operations to control costs, and
• Maintaining a strong balance sheet.

Annual Report Theme
“A Firm Foundation For The Future” was inspired by three
of more than 900 entries from employees in Devon’s annual
report theme contest. The winning entries were submitted
by Cristy Harrison in Houston, Debbie Little in Oklahoma
City and Linda Whelan in Calgary.

This annual report includes “forward-looking statements” as defined by the Securities and Exchange Commission. Such statements are those concerning Devon’s plans,
expectations and objectives for future operations including reserve potential and exploration target size. These statements address future financial position, business strategy,
f u t u re capital expenditures, projected oil and gas production and future costs. Devon believes that the expectations reflected in such forward-looking statements are re a s o n-
able. However, important risk factors could cause actual results to differ materially from the company’s expectations. A discussion of these risk factors can be found in the
“ M a n a g e m e n t ’s Discussion and Analysis . . .” section of this report. Further information is available in the company’s Form 10-K and other publicly available reports, which will
be furnished upon request to the company.

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FOR THE FUTURE

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Devon’s foundation for the future is supported by two vital elements:
the strength of our assets and the excellence of our employees.

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Featured employees clockwise, from upper left: Huy Tran, Oklahoma City; Paula Kupchak,
Calgary; Cassey Jones and John Walker, Bridgeport; and Eveline Chartier, Calgary.

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DEAR FELLOW SHAREHOLDERS

2002 will undoubtedly be remembered as a year of extraordinary achievement for Devon.

We drove total oil and gas production to 188 million equivalent barrels, an all-time record.

We successfully completed 1,599 oil and gas wells and a major acquisition. These activities

replaced 278% of the year’s production with new reserves at a cost of $7.18 per equivalent

barrel. Total revenues, total assets and shareholders’ equity all reached new highs. Although

not a record, net earnings also increased in 2002, to $104 million.

Building With Acquisitions

The results for 2002 reflect the impact of two acquisitions that nearly doubled the size of

the company: Mitchell Energy and Anderson Exploration. At this time a year ago, these

acquisitions had only recently been completed. Since then, the three organizations have been

melded into one.

On October 15, 2001, Devon completed the purchase of Canadian producer, Anderson.

The marriage of Anderson’s assets with Devon’s Canadian operations creates a formidable

Canadian independent. Devon now has a leading position in all of the major producing regions

J. Larry Nichols

in the Western Canadian Sedimentary Basin. Furthermore, our 11 million net undeveloped

acres in Canada provide Devon with one of the largest inventories of exploratory acreage in

that country.

We are gratified by the many former Anderson employees who chose to join with us to build upon Devon’s

foundation in Canada. During 2002, under the leadership of Devon Senior Vice President, John Richels, our Canadian

employees enthusiastically joined together to blend their cultures and their operations. Remarkably, this integration was

achieved without losing momentum in last year’s winter drilling program. In the period from mid-December 2001 to

mid-March 2002, we drilled 276 wells with an 88% success rate—an outstanding performance by any standard.

Simultaneously, Devon’s U.S. employees were busy integrating the operations of Mitchell. The development of

Mitchell’s crown jewel, the Barnett Shale gas properties in north Texas, progressed flawlessly during the transition. In

the 11 months of 2002 following the close of the Mitchell acquisition, production from the Barnett Shale climbed 40%

to 500 million equivalent cubic feet of gas per day. To accommodate this growth, we completed a significant expansion

of our Bridgeport gas plant. Furthermore, the drilling efficiencies and well completion improvements initiated by Mitchell

continue under the Devon flag. Over the last year we have further reduced the cost and time required to drill a Barnett

Shale well. These savings reflect the economies available to a larger, stronger company as well as the professionalism

and enthusiasm of the Mitchell employees who joined Devon.

Successfully integrating Anderson and Mitchell while maintaining focus on our day-to-day operations presented

an array of challenges across the organization. Devon’s staff, old and new, responded with dedication and

determination. It’s clear the acquisitions of Mitchell and Anderson added not only an abundance of high quality oil and

gas properties, but a wealth of human talent as well. I welcome each of these valued new employees to the Devon

family.

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Sharpening our Focus

In addition to integrating the high quality oil and gas properties of Anderson and Mitchell during 2002, we

significantly improved the focus of our operations. We completed a thorough review of all of the combined company’s

properties. We divested those with high operating costs, limited growth potential and those not significant to a

company of Devon’s new size. In total, we generated sales proceeds of $1.3 billion after tax, exceeding our

expectations. More importantly, the sale of these properties leaves Devon with a focused, highly profitable asset base

with abundant opportunities for growth.

A Firm Financial Foundation

In the acquisitions of Anderson and Mitchell, Devon issued approximately 30 million new common shares and

took on $6.7 billion in incremental debt. In March of 2002, we extended our debt maturity schedule with the issuance

of $1 billion of 30-year notes. In addition, following the Mitchell acquisition, we used the proceeds from property

divestitures and cash on hand to reduce long-term debt by $1.3 billion. The average after-tax interest rate on our

remaining debt is very low, about 3%. As a result, Devon enters 2003 with considerable financial strength and flexibility.

Aided by the strong oil and gas prices we are currently experiencing, we are generating significant cash flow over and

above our expected capital requirements. We have designated these funds to reduce debt and further fortify our

balance sheet.

Investing for the Long Run

In 2002, our investments in drilling and production facilities totaled $1.6 billion—the largest capital budget in our

history. With the successful completion of 1,599 oil and gas wells, we increased production from retained properties by

four million equivalent barrels. In addition to the $1.3 billion that generated this near-term production growth, we

invested approximately $300 million in longer-term, high-potential projects. These longer-term investments generated

two notable drilling successes during 2002. Tuk M-18 in Canada’s Mackenzie Delta and Cascade in the deepwater Gulf

of Mexico each promise significant future reserve additions.

PROVED OIL AND GAS RESERVES PER SHARE
(net of royalties) (Boe)

OIL AND GAS PRODUCTION PER SHARE
(net of royalties) (Boe)

11.67

10.09

10.26

7.58

7.49

6.02

1.22

.99

.89

.84

.78

01*

Since 1998, Devon has increased
reserves per share by 70%...

* 2001 reserves include 1.58 Boe per share
attributable to properties divested in 2002.

...and production per share by 56%.

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In 2003, Devon will invest about $370 million on long-term projects spread across a broad geographic spectrum. In

north Texas, we are exploring outside the core area in an attempt to extend the Barnett Shale play. Early results from

these wells are very encouraging. In 2002, we leveraged our exposure to the deepwater Gulf of Mexico through a multi-

well joint venture with ChevronTexaco. We expect to continue drilling exploratory wells during 2003 in this partnership.

Also in the deepwater Gulf, we expect to drill a follow-up to our Cascade discovery later this year. Outside North

America, Devon has an exploratory well planned for 2003 offshore Ghana in West Africa. We are also prospecting across

the Atlantic from Africa in waters offshore Brazil. While these projects cannot impact production or earnings in the near-

term, they represent the foundation for an attractive longer-term growth profile.

A Firm Foundation for the Future

As one of the largest natural gas producers in North America, Devon is positioned to reap the rewards of today’s

high natural gas prices. But to sustain Devon’s track record of success, we must look beyond today and plan for the

longer term. Our recently announced merger with Ocean Energy is an opportunity to do just that. Ocean brings to Devon

significant near-term growth projects, a large inventory of high-impact exploration projects and a wealth of talented

employees. The combined company will benefit from a better growth profile, a larger, higher-quality exploration inventory

and superior financial strength.

As I look ahead in 2003, I am more optimistic about Devon’s future than ever before. We have an abundance of

visible, low-risk growth opportunities from our portfolio of North American properties. We have longer-term growth

opportunities spanning from the Arctic Circle’s Mackenzie Delta to the waters offshore West Africa. And we are blessed

with the people and financial strength to capture these opportunities. Devon truly has established a firm foundation for

the future.

J. Larry Nichols

CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER

April 11, 2003

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FIVE -YEAR HIGHLIGHTS

Devon’s acquisition of Mitchell Energy on January 24, 2002, was recorded using the purchase method of accounting.
Therefore, the information presented below includes Mitchell’s results from January 24 through December 31, 2002, only.

YEAR ENDED DECEMBER 31,

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

FINANCIAL DATA ( 1 ) (Millions, except per share data)

Total re v e n u e s ( 2 )
Operating costs and expenses
E a rnings from operations

Other expenses
Total income tax expense (benefit)
Net earnings (loss) from continuing operations

Net results of discontinued operations

Net earnings (loss) applicable to common shareholders

Net earnings (loss) per share :

B a s i c
D i l u t e d

Weighted average common shares outstanding:

B a s i c
D i l u t e d

Operating cash flow from continuing operations
Operating cash flow from discontinued operations

Net cash provided by operating activities

Cash dividends per common share ( 3 )

DECEMBER 31,

Total assets
D e b e n t u res exchangeable into shares of

C h e v ro n Texaco Corporation common stock ( 4 )

Other long-term debt ( 5 )
Stockholders’ equity
Working capital

P R O P E RTY DATA ( 1 )

P roved re s e r v e s (Net of ro y a l t i e s )

O i l ( M M B b l s )
G a s ( B c f )
Natural gas liquids ( M M B b l s )
To t a l ( M M B o e ) ( 6 )
10% present value before income taxes ( M i l l i o n s )
10% present value after income taxes ( M i l l i o n s )

$
$
$

$
$

$
$
$

$
$
$
$

$
$

604
861
( 2 5 7 )

4 7
( 1 0 3 )
( 2 0 1 )

( 3 5 )

( 2 3 6 )

1,140
1,309
( 1 6 9 )

9 9
( 7 5 )
( 1 9 3 )

( 1 5 8 )

2,587
1,431
1,156

2,864
2,672
192

1 1 8
377
661

720

1 6 4
5
23

4,316
3,775
541

6 7 5
( 1 9 3 )
59

( 3 . 3 2 )
( 3 . 3 2 )

( 1 . 6 8 )
( 1 . 6 8 )

5.66
5.50

0.73
0.72

0.61
0.61

71
77

308
22
330

94
99

452
87
539

127
132

1,479
110
1,589

128
130

1,776
134
1,910

155
156

1,726
28
1,754

0.10

0.14

0.17

0.20

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

LAST YEAR
C H A N G E

1,931

6,096

6,860

13,184

16,225

2 3 %

885
750
( 2 9 )

760
1,656
2,521
85

760
1,289
3,277
251

166
1,440
21
427
1,375
1,321

439
2,785
55
958
5,316
4,465

406
3,045
50
963
17,075
12,065

649
5,940
3,259
435

527
5,024
108
1,472
6,687
5,015

662
6,900
4,653
22

444
5,836
192
1,609
15,307
10,365

LAST YEAR
C H A N G E

5 1 %
4 1 %
1 8 2 %

3 1 2 %
NM
1 5 7 %

4 5 %

1 1 4 %

( 1 6 % )
( 1 5 % )

2 1 %
2 0 %

( 3 % )
( 7 9 % )
( 8 % )

2 %
1 6 %
4 3 %
( 9 5 % )

( 1 6 % )
1 6 %
7 8 %
9 %
1 2 9 %
1 0 7 %

LAST YEAR
C H A N G E

YEAR ENDED DECEMBER 31,

1 9 9 8

1 9 9 9

2 0 0 0

2 0 0 1

2 0 0 2

P ro d u c t i o n (Net of ro y a l t i e s )

O i l ( M M B b l s )
G a s ( B c f )
Natural gas liquids ( M M B b l s )
To t a l ( M M B o e ) ( 6 )

20
189
3
55

25
295
5
79

37
417
7
113

36
489
8
126

42
761
19
188

1 7 %
5 6 %
1 3 8 %
5 0 %

(1) All of the years shown exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002.

Data has also been reclassified to reflect the 1998 merger of Devon and Northstar and the 2000 merger of Devon and Santa Fe Snyder in accordance
with the pooling-of-interests method of accounting. Revenues, expenses and production in 2002 include only eleven and one-fourth
months attributable to the Mitchell acquisition; in 2001 include only two and one-half months attributable to the Anderson acquisition;
and in 1999 include only eight months activity attributable to the Snyder Oil transaction and four and one-half months activity attributable to the
PennzEnergy transaction.

(2) Excludes other income.
(3) The cash dividends per share presented for 1998 through 2002 are not representative of the actual amounts paid by Devon because of mergers accounted

for as poolings. For the years 1998 through 2000, Devon's historical cash dividends per share were $0.20 in each year.

Includes preferred securities of subsidiary trust of $149 million in 1998.

(4) Debentures exchangeable into seven million shares of ChevronTexaco common stock beneficially owned by Devon.
(5)
(6) Gas converted to oil at the ratio of 6 Mcf:1 Bbl. Natural gas liquids converted to oil at the ratio of 1Bbl:1Bbl.
NM Not a meaningful number.

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Devon drills this exploratory well in Canada’s Mackenzie Delta.
Drilling is limited to the winter months when the ground is frozen and can accommodate heavy equipment.

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“As a Devon field employee in Canada, I work with one of the largest
and highest quality property bases in this country. Our assets range
from dependable, long-lived oil properties in central Alberta to high-
impact exploration opportunities within the Arctic Circle.”

S TAFFORD WILSON – BURMIS, ALBERTA

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EXECUTIVE Q&A

Devon completed five large mergers and acquisitions
over the last five years and has recently agreed to
merge with Ocean Energy. Can we expect this process
to continue?

Devon invested $1.5 billion in exploration and
development last year but failed to replace 100% of
production with drilling. Do you expect this to improve
in the future?

Larry Nichols, Chairman, President and CEO:

Mike Lacey, Senior Vice President – Exploration and

Historically, the North American oil and gas industry

Production:

was far too fragmented for optimal efficiency. The
consolidation that has been under way over the last 15
years has yielded fewer companies with better access to
capital, better access to technology and greater economies
of scale. Devon’s shareholders have benefited from our
participation in this consolidation. Devon has emerged as
one of the largest and most efficient oil and gas producers
in North America. Following the completion of our merger
with Ocean, we will also have improved internal growth
prospects and the financial strength to pursue both drilling
and acquisitions. We will continue to evaluate potential
mergers and acquisitions and are prepared to act should
the right opportunity become available.

Devon repaid $1.3 billion in debt in 2002. Are you
comfortable with current debt levels or can we expect
further repayments this year?

Brian Jennings, Senior Vice President – Corporate

Development:

Maintaining a strong balance sheet and a high degree

of financial flexibility has always been a high priority for
Devon. This allows us to utilize our balance sheet to seize
growth opportunities when they become available. In late
2001 and early 2002, we elected to increase long-term
debt to capture the extraordinary potential we saw in the
Anderson and Mitchell acquisitions. We planned on using
the proceeds from the sale of non-core properties and
cash generated from operations to reduce indebtedness to
levels more in line with our historic norms. With the
progress we made in 2002, we were well on our way to this
goal by year-end. Thus far in 2003, Devon is generating
cash flow well in excess of our capital needs. This is
allowing us to accumulate significant cash balances that
we are earmarking for further debt repayment.

Yes. While it is correct that we replaced only about

75% of our production with the drill bit in 2002, that
doesn’t really tell the whole story. In addition to the 142
million equivalent barrels of reserves that we recorded as
additions during 2002, Devon made significant investments
in longer-term, high-impact projects intended to add
reserves and production in future years. The fruits of the
$300 million plus we invested in 2002 for long-term growth
include two successful high-impact wells that are not yet
reflected in our reserves. We expect these wells, the Tuk
M-18 in the Mackenzie Delta and the Cascade well in the
deepwater Gulf of Mexico, to deliver significant reserve
additions in the future.

While directing capital to these longer-term

investments negatively impacts our reported finding costs
and reserve replacement over the short run, it is projects
like this that are expected to fuel Devon’s growth and lower
our finding costs over the long run.

A number of high profile companies have been accused
of reporting irregularities. How can we be sure Devon
is conducting its business ethically?

Bill Vaughn, Senior Vice President – Finance:

It is Devon’s policy to adhere to the highest ethical

s t a n d a rds. This policy applies not only to accounting, but
extends to all of our business practices. Devon rigoro u s l y
strives to strictly comply with all regulations in every place
that we do business. In the area of securities regulation, we
welcome effective regulatory efforts to provide a level
playing field for all investors and strongly support these
e fforts. Should our employees encounter any evidence of
ethical misconduct, they are encouraged to report the
situation and we pledge to respond pro m p t l y.

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Devon has discovered significant natural gas reserves
in Canada’s far north. When do you believe that gas
will be brought to market?

John Richels, Senior Vice President – Canadian Division:
The Mackenzie Delta and Beaufort Sea have the
potential to supply a significant portion of North America’s
growing demand for clean burning natural gas. Devon is
the largest holder of exploration licenses and concession
acreage in this highly prospective area. In 2002, a Devon
well in the Mackenzie Delta encountered 200 to 300 billion
cubic feet of potential gas reserves for Devon and its
partner.

The challenge ahead is to bring this valuable resource
to markets in the south. Various gas transmission pipeline
projects are currently under consideration for this stranded
resource. While Devon does not expect to participate in
the construction of a pipeline, we do expect to transport
gas through the finished line. Present projections for the
completion of a Mackenzie Valley pipeline are 2007 to
2008, and we are encouraged by the current momentum.
Our objective is to have significant gas ready to ship when
the pipeline is completed.

You sold your interests in Argentina and Indonesia in
2002. Do you plan to sell your remaining assets outside
North America?

Larry Nichols:

Although we chose to divest those international
assets, this does not mean that we are disinterested in all
international opportunities. We have retained our oil
development projects in China and Azerbaijan. In addition,
we are actively exploring offshore West Africa and Brazil.
Going forward, we will continue to pursue international
growth opportunities in areas that meet our investment
criteria. In general, we are attracted to countries that offer
stable political environments, favorable fiscal regimes,
access to strong or growing product markets and projects
with the potential to be significant to Devon as a whole.

C O R P O R ATE GOVERNANCE

Devon takes its fiduciary responsibility to its
shareholders and investors seriously. In light of recent
accounting failures at some high-profile companies, we
have initiated a broad-based financial stewardship
program to provide even more focus on internal controls
and accounting processes. These initiatives include:

• Full compliance with all provisions of the Sarbanes-
Oxley Act of 2002. We view this new legislation as an
opportunity to assess and strengthen the company’s
governance policies and procedures.

• Adoption of procedures for auditor independence.
KPMG LLP, our independent audit firm, continues to
report directly to the Audit Committee of our board of
directors.

• Establishment of a corporate disclosure committee to
oversee public disclosure and regulatory filings. This
committee ensures that Devon provides balanced, timely
and accurate disclosures that comply with all legal and
regulatory requirements.

• Promotion of a strong ethical climate throughout the
organization. Devon’s management, with the full support
of the board of directors, is committed to maintaining the
highest ethical standards of personal and corporate
conduct.

These initiatives are consistent with how Devon has

operated for decades. We continually review the
organization’s commitment to these initiatives and
reaffirm this commitment to our shareholders.

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Devon’s Bridgeport, Texas, gas plant processes the liquids-rich gas from our prolific Barnett Shale project.
By owning and managing gas processing operations, Devon can enhance the economic returns of its development projects.

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“As a reservoir engineer, I’m involved in oil and gas exploration
and development projects. Our asset team evaluates
new opportunities in unexplored areas
and new reserve potential in existing fields.”

S H I L PA ABBITT – OKLAHOMA CITY, OKLAHOMA

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E X P L O R ATION AND PRODUCTION PORT F O L I O

O ff s h o re production facilities for Devon ’s Panyu project in the South China Sea are under construction in Singapore.
Installation and first oil production are expected by year-end 2003.

The Anderson and Mitchell acquisitions of late 2001

and early 2002 dramatically expanded the company’s
property base, making Devon one of North America’s
largest producers of oil and natural gas. More importantly,
by acquiring Anderson and Mitchell’s high-quality
properties and divesting non-core and low-growth
properties, we have significantly improved the profitability
and long-term growth potential of our oil and gas asset
base.

As we enter 2003, more than 98% of Devon’s total oil
and natural gas production comes from the western United
States, the Gulf of Mexico and western Canada. About
two-thirds of this production is natural gas. And while the
majority of our 2003 capital budget is focused on low-risk
and moderate-risk drilling projects in these core areas, we
also have meaningful exposure to longer-term high-impact
exploration. This balance provides Devon with a firm
foundation for growth well into the future.

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THE BARNETT SHALE
Exceeding high expectations

Devon’s Barnett Shale project in the Fort Worth Basin

of north Texas is among the fastest growing and most
exciting onshore natural gas plays in North America. The
Barnett Shale is a “tight” reservoir. In tight formations, gas
does not flow freely to the wellbore. Stimulation is required
to release the gas trapped within the rock. Light sand
fracturing (see inset story on page 20) is the stimulation
method that has transformed the Barnett Shale into the
largest gas field in the state of Texas.

It was the dramatic production growth from the
Barnett Shale that initially attracted Devon to Mitchell
Energy. But the property has exceeded even our
expectations. When we announced our plans to buy
Mitchell in August 2001, the Barnett was producing about
350 million equivalent cubic feet of gas per day. Since
closing the transaction in January 2002, production has
steadily increased. By mid-year 2002, the Barnett was
producing 425 million per day and it now produces over
500 million per day. This represents about one-fourth of
Devon’s total U.S. oil and gas production.

The Barnett Shale holds tremendous additional
potential for Devon. We control 545,000 net acres in the
area and have developed less than one-fourth of this
acreage to date. The undeveloped portion represents
thousands of potential undrilled locations. In 2002, Devon
drilled 385 Barnett wells, bringing the number of producing
wells to about 1,200. We plan to drill another 450 new
wells in 2003.

In addition to traditional vertical drilling, we are
experimenting with horizontal drilling in the Barnett Shale.
Because a horizontal well can drain a broad area, fewer
wells may be required to produce the same amount of gas.
A typical vertical Barnett Shale well produces about 1
million cubic feet of gas per day when first brought on
production. By comparison, early stage horizontal wells are
producing three to four times that amount. If these early
tests prove to be representative over time, horizontal
drilling may further enhance the economic and reserve
recovery characteristics of Devon’s Barnett Shale assets.
Furthermore, horizontal drilling may allow development of
areas that could not be developed with vertical wells. We
have drilled nine horizontal wells in the Barnett Shale to
date and the results are very promising.

In addition to acquiring Mitchell’s exploration and
production operations, we also acquired its substantial
natural gas transportation and processing business. Gas
processing allows for the extraction of natural gas liquids
such as ethane, propane and butane from the gas stream.
Owning processing facilities, especially in liquids-rich areas
like the Barnett Shale, gives us greater control over the
sale and distribution of our products. This in turn can
improve economic returns and ensure that we have
adequate gas transmission and processing capacity when
needed. A series of expansions at our Bridgeport plant in
north Texas has allowed us to keep pace with the rapid
production growth of Devon’s Barnett gas production.
At a time when North American natural gas

production is showing signs of industry-wide decline, the
Barnett Shale is bucking that trend. Devon’s control of this
extraordinary resource represents a unique opportunity for
growth.

COALBED METHANE
Building on our experience

Over the last decade, natural gas produced from
underground coal deposits, “coalbed methane,” has been
one of the fastest growing energy sources in North
America. This non-conventional natural gas production is
characterized by minimal drilling risk, low development
costs and low operating costs. It differs from conventional
natural gas in that production generally starts out low and
increases throughout the early lives of the wells. As the
water is pumped out of the coal, the well is “dewatered”
and gas production increases.

Devon was a pioneer in coalbed methane pro d u c t i o n

in the mid-1980s in the San Juan Basin of New Mexico.
Since then, we have exported our expertise to the Powder
River Basin of Wyoming. We also have early-stage pilots in
Louisiana and western Canada.

In the Powder River Basin, Devon drilled 140 coalbed

methane wells in 2002. We have drilled more than 1,500
wells since we first began the project in 1998. At the end
of 2002, Devon’s share of production from these wells was
about 80 million cubic feet of gas per day. Our current
Powder River production is primarily from the shallower
Wyodak coals, generally found at depths of less than
1,000 feet. The deeper Big George coals represent
additional growth potential. Devon has four Big George

8626pg01_23_04-11 6/21/04 12:15 PM Page 16

pilot projects under way, three of which are now producing
commercial quantities of gas. Should they prove
successful, we will drill many more Big George wells in the
future.

A NATURAL GAS POWERHOUSE
At the wellhead and beyond

Devon produces more than 2 billion cubic feet of
natural gas each day or about 3% of all the gas consumed
in North America. About one-fourth of that production is
from non-conventional sources such as the Barnett Shale
and coalbed methane. The balance is produced from
conventional producing areas in the United States and
Canada.

Devon’s conventional production areas include the

Permian Basin of southeastern New Mexico and west
Texas. In 2002, Devon drilled 120 wells in the Permian,
including successful programs in our Anton Irish and
Indian Basin fields.

Another important contributor to Devon’s
conventional gas production is the Washakie field in
southwest Wyoming. Devon has achieved steady
production growth from this field, currently producing
about 80 million cubic feet of gas per day. We drilled 31
Washakie wells in 2002 and plan another 30-well program
in 2003. With more than 200,000 net acres and several
hundred undrilled locations, we will be actively drilling here
for years to come.

Western Canada, where Devon produces from the

most prolific gas-prone basins, accounts for more than a
third of our natural gas production. Devon is actively

drilling in the Deep Basin, northeast British Columbia and
Foothills regions. We expect to increase our Deep Basin
production over the next few years, from about 90 million
cubic feet per day in 2002 to over 140 million per day in
2005. In the Foothills, where we currently produce about
115 million cubic feet per day, we expect to increase
production as we tie in recent discoveries in the Grizzly
Valley area to a pipeline set for completion by mid-year.

Complementing Devon’s producing operations is our
network of gas transmission and processing, or midstre a m ,
facilities. With ownership in 69 natural gas processing
plants in the United States and Canada, Devon has one of
the largest midstream operations of any independent. We
are also one of the largest independent producers of
natural gas liquids.

GULF OF MEXICO SHELF
Better seismic imaging reduces drilling risk

The Gulf of Mexico shelf, defined as water depths of
up to 600 feet, accounted for about 10% of Devon’s 2002
production. Devon has been successful by leveraging our
extensive shelf infrastructure of production facilities and by
applying the latest technological tools. An example is
Devon’s application of four-component, or 4-C, seismic.
This innovative technology is proving to be quite effective
in reducing drilling risk. In the West Cameron area of the
Gulf, Devon has successfully completed four of five
exploratory wells drilled on 4-C data. These four wells
initially produced a combined 66 million cubic feet of gas
per day. Devon plans to drill additional wells based on 4-C
seismic during 2003.

R E S E RV E S
(net of royalties) (MMBoe)

1,609

1,472

958

963

427

OIL AND GAS PRODUCTION
(net of royalties) (MMBoe)

188

126

113

The Mitchell acquisition and new drilling
increased proved oil and gas reserv e s
to 1.6 billion equivalent barrels...

...and pushed oil and gas production
to record levels in 2002.

8626pg01_23_04-11 6/21/04 12:15 PM Page 17

The Gulf of Mexico shelf has been drilled for more

than 50 years, but relatively few wells have penetrated
deeper than 15,000 feet. With the aid of government
incentives, a new wave of exploratory drilling is taking
place on the “deep shelf,” below 15,000 feet. Applying the
latest seismic imaging technology is improving the
chances for success with deep shelf targets. Devon has
identified 10 deep shelf prospects with an estimated 1.4
trillion cubic feet of reserve potential. We expect to drill
three deep shelf wells in 2003.

GULF OF MEXICO DEEPWATER
An exciting discovery and a new joint venture

Compared to the shelf, the deepwater Gulf of Mexico
is a relatively new frontier. Industry has moved into deeper
and deeper water in step with advances in drilling and

production technology. In May 2002, Devon’s Cascade
well discovered what appears to be a very large
hydrocarbon-bearing structure in 8,200 feet of water. A
delineation well planned for late this year will attempt to
further define the size and quality of the reservoir. If those
results support further investment, Devon and its partners
will evaluate various alternatives for the development of
this discovery.

Because costs are much greater in the deep water

than on the shelf, we utilize partnerships and joint ventures
to limit exposure to any single project. In 2002, Devon
joined with ChevronTexaco to participate in four
exploratory wells in exchange for a 25% working interest
in 71 deepwater blocks. These blocks, combined with
Devon’s own extensive holdings of deepwater acreage,
provide an inventory of high-impact exploratory drilling
prospects for several years forward.

F O U R - C O M P O N E N T
S E I S M I C

Seismic data is used
to create visual images of
underground rock
formations. Geoscientists
use these images as a
means to help identify oil
and gas deposits and to
minimize drilling risk.
Although seismic
technology has been
around for decades, only
recently have dramatic
increases in computing
power and new seismic recording techniques made four-component (4-C) seismic possible.

To capture the necessary seismic energy, long cables with recording “pods” spread about 50 yards apart are lowered
to the ocean bottom from a recording vessel. The recording pods receive seismic wave signals and transmit them back to
the vessel. Each pod is enclosed in a steel cage weighing about 75 pounds. The cages settle into the soft ocean bottom to
ensure good contact with the earth. Once the cables are in place, a source vessel creates a series of compressed airbursts.
Each airburst produces a seismic or sound wave. The seismic waves are transmitted down into the earth where rock layers
reflect the waves back up towards the ocean bottom where they are recorded.

The term “four-component” refers to the orientation of the four separate recording devices housed in each pod. Each

device is oriented in a specific direction to record different wave components. The addition of two horizontal geophones
inside the pod that measure shear wave signals differentiate 4-C from traditional 2-D or 3-D seismic surveys. Shear waves
do not travel through water, so marine surveys must use cables that make contact with the ocean’s bottom.

An advantage of 4-C seismic is that it allows geoscientists to “see” beneath shallow gas accumulations just below the

ocean bottom and to better define the oil and gas reservoirs below.

8626pg01_23_04-11 6/21/04 12:16 PM Page 18

This deepwater r ig drilled a nat ural gas discovery for Devon off s h o re Mississippi in the Gulf of Mexico.

8626pg01_23_04-11 6/21/04 12:16 PM Page 19

“Devon is exploring for oil and gas in the deep waters of the Gulf of
Mexico and West Africa. As the company’s supervisor of deepwater
drilling operations, I’m proud to be at the forefront of this effort.”

DANNY HOGAN – HOUSTON, TEXAS

8626pg01_23_04-11 6/21/04 12:16 PM Page 20

CANADIAN HEAVY OIL
Vast potential

FRACTURE STIMULAT I O N

Oil and natural gas deposits are found trapped

in the pores of underground rock formations. The
characteristics of different formations determine how
easily oil and gas moves within these pores. Some
formations, such as the Barnett Shale, are so “tight”
that movement is severely restricted. In such tight
formations, it is often necessary to hydraulically
fracture the formation to stimulate the movement of
oil or gas into a wellbore so it can be brought to the
surface.

Fracturing creates small cracks within

subsurface rock formations. These cracks, or
fractures, serve as pathways to allow the oil and gas
to flow more easily. Fluid is pumped into the
formation under extreme pressure to fracture the
rock. Particles, such as sand, are mixed with the
fluid. After the fracturing process is complete, the
fluid drains away, leaving behind the particles. The
particles, or proppant, prevent the fractures from
closing up again. The newly created pathways
remain open for the oil or gas to travel toward the
wellbore and to the surface.

The “light sand” fracturing method adapted to
Devon’s Barnett Shale play utilizes water with sand
as the proppant. A typical Barnett Shale light sand
fracture requires 850,000 gallons of water and
100,000 pounds of sand to create fractures that
extend about 1,500 feet from the wellbore.

With our 2001 acquisition of Anderson, Devon

acquired both conventional cold-flow and thermal heavy oil
assets in eastern Alberta. Although more dense than
conventional crude oil, cold-flow heavy oil can be
produced in its natural state. Thermal heavy oil is so dense
that it will not flow unless heated. Heat is typically applied
by injecting steam into the formation.

Devon’s 2002 cold-flow drilling program at

Lloydminster increased our oil production by 5,700 barrels
per day. Based on these results, the company is
continuing to actively drill at Lloydminster in 2003. Devon’s
Canadian heavy oil assets also include 300,000 net acres
of thermal oil leases. The company plans to invest $35
million in thermal heavy oil projects in 2003.

MACKENZIE DELTA
A future gas pipeline could unlock value

The search for natural gas extends to the northern
reaches of our continent, into Canada’s Mackenzie Delta
and the shallow waters of the Beaufort Sea. With 1.5
million net acres, Devon is the largest exploratory
landholder in these areas. Early in 2002, Devon made one
of the largest finds in recent years in the Mackenzie Delta.
Our Tuk M-18 well, in which we have a 50% working
interest, tested significant natural gas flows with gross
estimated potential reserves of 200 to 300 billion cubic
feet. Recent progress toward construction of a pipeline
means Mackenzie Delta gas could be flowing to markets in
southern Canada and the United States in the second half
of this decade. Devon plans to drill additional exploratory
wells in the Mackenzie Delta in the future.

INTERNATIONAL DEVELOPMENTS
Oil from China and drilling in West Africa

Devon first discovered oil in the South China Sea in

1998. A second discovery the following year gave the
Panyu project critical mass, with an estimated 80 million
barrels of gross reserves. Construction of production
facilities is nearing completion, and we expect to see oil
flowing in the fourth quarter of 2003. Devon’s share is
expected to reach 15,000 barrels per day in 2004.

Devon’s international exploration program is focused
on the South Atlantic Margin, in the waters offshore West
Africa and Brazil. We are conducting extensive seismic
surveys in both regions where we see similar play
concepts. We also plan to drill an exploration well offshore
Ghana in 2003.

8626pg01_23_04-11 6/21/04 12:16 PM Page 21

E N V I R O N M E N TAL, HEALTH AND SAFETY: TOP PRIORITIES AT DEVON

Devon conducts its operations in accordance with the highest levels of employee, social and environmental

responsibility. We believe this commitment is essential to fulfill our business goals and the expectations of our employees
and shareholders. During 2002, Devon undertook initiatives to reinforce its commitment to these high standards that
included:

• Adopting an enhanced Environmental, Health and Safety (EHS)

Philosophy

• Implementing a program of consistent “best practices” throughout
the company to ensure that all employees and contractors clearly
understand Devon’s EHS expectations

• Initiating a comprehensive review and update of all Devon EHS

policies

• Adopting an EHS management system

Health and Safety

At Devon, occupational health and safety values will not be
compromised. We heighten safety awareness through a comprehensive
program reinforced by safety performance and incident investigation
training. We also prepare and plan for catastrophic events. In 2002,
Devon updated and enhanced its emergency response and business
recovery contingency plans.

Environmental Stewardship

We understand the vital relationship between our operations and
the environment. To limit and mitigate environmental impact, we seek
and adopt technically sound and economically feasible controls
wherever we operate.

Devon is routinely recognized by trade organizations and

governmental agencies for our commitment to protecting the
environment. Recent recognition included:

• One of only 13 companies recognized at the highest Platinum level

of participation in the Canadian Association of Petroleum
Producers’ EHS Stewardship Program

• Wyoming Game and Fish Department 2002 Coalbed Methane

Photo Courtesy of Gillette News Record

Thom Holmes, operations engineer, surveys land
on a Wyoming ranch where the company’s
coalbed methane development has provided
much needed water for the area.

Natural Resource Stewardship Award. The award recognized Devon’s efforts to minimize habitat disturbance on drilling
sites and to utilize groundwater released in producing coalbed methane to enhance wildlife habitat.

Commitment

Not only is Devon committed to complying with all applicable environmental, health and safety laws and regulations,

we strive to keep our operations compatible with the communities where we do business. We expect to continue to
achieve excellence in environmental, health and safety performance through the active participation and support of our
management, employees and contractors.

8626pg01_23_04-11 6/21/04 12:16 PM Page 22

O P E R ATING STATISTICS BY AREA

Producing Wells at Year-End

2002 Production (Net of royalties) (1)

Oil (MMBbls)
Gas (Bcf)
Natural Gas Liquids (MMBbls)
Total (MMboe) (2)

Average Prices (1)

Oil ($/Bbl)
Gas ($/Mcf)
Natural Gas Liquids ($/Bbl)

Year-End Reserves (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
Natural Gas Liquids (MMBbls)
Total (MMboe) (2)

Year-End Present Value of Reserves (Millions) (3)

Before Income Tax
After Income Tax

Year-End Leasehold (Net acres in thousands)

Producing
Undeveloped

Wells Drilled During 2002 (1)

2002 Exploration, Development and
Facilities Expenditures (Millions) (1,4)

Estimated 2003 Exploration, Development &

Facilities Expenditures (Millions) (5)

$
$
$

$
$

P E R M I A N

M I D –
C O N T I N E N T

R O C K Y
M O U N TA I N S

G U L F
C O A S T

G U L F
O F F S H O R E

6,651

5,092

3,045

1,050

663

11
61
2
23

22.42
3.29
14.72

90
283
13
150

2
191
9
43

21.73

2.74

12.54

9
2,103
116
475

3
104
1
21

20.90
2.39
16.94

22
835
9
170

1,418

3,918

1,100

297
462

120

783
1,179

579

440

287
601

196

105

1
42
1
9

7
84
1
22

22.46
3.30
14.63

21.70
3.47
14.06

3
137
4
30

382

243
91

23
194
4
60

922

286
467

292

T O TAL
U . S .

16,501

24
482
14
118

21.99
2.91
13.37

147
3,552
146
885

7,740
5,510

1,896
2,800

979

996

60 - 70

400 - 450

65 - 75

70 - 80

250 - 280

845 - 955

(1) Excludes results from discontinued operations.
(2) Gas converted to oil at the ratio of 6 Mcf:1 Bbl. Natural gas liquids converted to oil at the ratio of 1Bbl:1Bbl.
(3) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs,

discounted at 10% in accordance with Securities and Exchange Commission guidelines.

(4) Excludes $108 million spent on marketing and midstream assets.
(5) Excludes $150 to $170 million expected to be spent on marketing and midstream assets.

11-YEAR PROPERTY DATA ( 1 )

Reserves (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
Natural Gas Liquids (MMBbls)
Total (MMBoe) (2)
10% Present Value (Millions) (3)

Production (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
Natural Gas Liquids (MMBbls)
Total (MMBoe) (2)

Average Prices
Oil (Per Bbl)
Gas (Per Mcf)
Natural Gas Liquids (Per Bbl)
Oil, Gas and Natural Gas Liquids (Per Boe) (2)

Production and Operating Expense per Boe (2)

19 9 2

19 9 3

19 9 4

19 9 5

19 9 6

264
645
7
379
1,333

25
80
1
39

14.88
1.63
12.27
13.06

5.25

$
$
$
$

257
709
7
382
1,074

27
106
1
46

12.94
1.77
12.51
12.04

4.91

294
744
12
430
1,485

27
101
1
45

12.99
1.69
10.17
11.84

4.83

313
860
16
472
1,872

28
109
1
47

15.07
1.44
10.62
12.49

4.69

351
1,131
18
558
3,952

30
116
2
52

17.49
1.82
13.78
14.90

5.24

(1) All of the years shown exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002

Data has been restated to reflect the 1998 merger of Devon and Northstar and the 2000 merger of Devon and Santa Fe Snyder in accordance with the
pooling-of-interest method of accounting.

(2) Gas converted to oil at the ratio of 6 Mcf:1Bbl. Natural gas liquids converted to oil at the ratio of 1Bbl:1Bbl.
(3) Before income taxes.

19 9 7

219
1,403
24
477
2,100

29
180
3
62

17.03
2.04
12.61
14.51

4.63

8626pg01_23_04-11 6/21/04 12:16 PM Page 23

G U L F
O F F S H O R E

T O TAL
U . S .

C A N A D A

I N T E R N AT I O N A L

T O TA L
C O M PA N Y

2003 EXPLORATION, DEVELOPMENT
AND FACILITIES BUDGET

16,501

6,874

23,395

INTERNATIONAL

PERMIAN

663

7
84
1
22

21.70
3.47
14.06

23
194
4
60

922

286
467

292

24
482
14
118

21.99
2.91
13.37

147
3,552
146
885

7,740
5,510

1,896
2,800

979

996

16
279
5
68

21.00
2.62
15.93

149
2,284
46
576

6,258
3,890

2,296
11,468

661

534

2
-
-
2

23.70
-
-

148
-
-
148

1,309
965

6
7,437

42
761
19
188

21.71
2.80
14.05

444
5,836
192
1,609

15,307
10,365

4,198
21,705

1,685

1,587

0 - 280

845 - 955

460 - 540

80 - 105

1,385 - 1,600

MID-
CONTINENT

28%

CANADA

34%

GULF
OFFSHORE

18%

ROCKY
MOUNTAINS

GULF COAST

PROVED OIL AND GAS RESERV ES
B Y AREA

INTERNATIONAL

PERMIAN

CANADA

36%

MID-
CONTINENT

29%

GULF
OFFSHORE

ROCKY
MOUNTAINS

11%

GULF COAST

19 9 6

351
1,131
18
558
3,952

30
116
2
52

17.49
1.82
13.78
14.90

5.24

the

19 9 7

19 9 8

19 9 9

200 0

20 0 1

2 0 0 2

5–YEAR COMPOUND 10–YEAR COMPOUND

GROWTH RAT E

219
1,403
24
477
2,100

29
180
3
62

17.03
2.04
12.61
14.51

4.63

166
1,440
21
427
1,375

20
189
3
55

12.28
1.78
8.08
11.09

4.29

439
2,785
55
958
5,316

25
295
5
79

17.78
2.09
13.28
14.22

4.15

406
3,045
50
963
17,075

37
417
7
113

24.99
3.53
20.87
22.38

4.81

527
5,024
108
1,472
6,687

36
489
8
126

21.41
3.84
16.99
22.19

5.29

444
5,836
192
1,609
15,307

42
761
19
188

21.71
2.80
14.05
17.61

4.71

15%
33%
51%
28%
49%

8%
33%
46%
25%

5%
7%
2%
4%

5%
25%
40%
16%
28%

5%
25%
40%
17%

4%
6%
1%
3%

(1%)

8626pg024_28_04-11 6/21/04 12:20 PM Page 1

KEY PROPERTY HIGHLIGHTS

NEW
MEXICO

KANSAS

OKLAHOMA
OKLAHOMA

TEXAS
TEXAS

MEXICO

Permian

Southeast New Mexico

Profile
• 340,000 net acres in southeast New Mexico.
• 65% average working interest.
• Key fields include Indian Basin, Catclaw Draw

and Outland/Gaucho.

• Produces oil and gas from multiple formations

at 1,500’ to 12,500’.

• 47.4 million barrels of oil equivalent reserves

at 12/31/02.
2002 Activity
• Drilled and completed 17 gas wells.
• Drilled and completed 10 oil wells.
2003 Plans
• Drill 17 gas wells.
• Drill up to 23 oil wells.
• Evaluate recompletion opportunities.

KANSAS

OKLAHOMA

TEXAS

Mid-Continent

Cherokee Coalbed Methane

Profile
• 420,000 net acres in southeast Kansas and

northeast Oklahoma.
• 100% working interest.
• Initiated in 2001.
• Produces coalbed methane from multiple coal

seams at 800’ to 2,700’.

• Access to major gas pipelines.
• 22.8 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Drilled 137 coalbed methane wells.
• Completed 206 coalbed methane wells including

wells drilled in 2001.

• Constructed 127 miles of gas transmission lines.
• Connected 186 wells to gas sales.
• Installed 167 pumping units for water removal.
2003 Plans
• Complete wells drilled in 2002.
• Drill 143 additional coalbed methane wells.
• Drill 5 water disposal wells.
• Recomplete 33 wells.
• Continue development of gas transmission s y s t e m .

WYOMING

UTAH

COLORADO

Barnett Shale

ARIZONA

Profile
• 545,000 net acres in the Fort Worth Basin

of north Texas.

• 95% average working interest.
• Obtained in 2002 acquisition.
• Produces gas from the Barnett Shale formation

at 6,500’ to 8,500’.

• 298.1 million barrels of oil equivalent reserves

at 12/31/02.
2002 Activity
• Drilled 380 development wells, including:
32 infill wells on 27-acre spacing.
4 horizontal wells.

• Drilled 5 exploratory wells, including:

3 horizontal wells.

• Refractured 144 wells.
• Completed 2-D and 3-D seismic acquisitions.
• Completed 6th expansion of Bridgeport Plant.
• Constructed 210 miles of gas transmission lines.
• Connected 376 Devon wells to gas sales.
2003 Plans
• Drill approximately 450 development wells.
• Drill 8 exploratory wells.
• Expand horizontal drilling program according to

well performance.
• Refracture 64 wells.
• Continue infill-drilling program.

Carthage/Bethany Area

NEW MEXICO

Rocky Mountains

Powder River Coalbed Methane

Profile
• 200,000 net undeveloped and 50,000 net
developed acres in northeastern Wyoming.

• 75% average working interest.
• Initial position obtained in 1992 acquisition.
• Produces coalbed methane from the Fort Union

Coal formations at 300’ to 2,000’.

• 11.5 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Drilled 140 coalbed methane wells (over 120

wells awaiting connection to gas transmission
system at year-end).

• Connected 216 wells to gas sales.
• Connected 2 Big George pilots to sales at Pine

Tree.
2003 Plans
• Connect remaining wells drilled in 2002 to

gas transmission system.

• Drill 113 additional coalbed methane wells.
• Recomplete 22 Wyodak coal wells.
• Connect Big George pilot to sales at Juniper

Profile
• 65% to 85% working interest in 77,000 acres in

Draw.

• Permit 201 wells on federal lands.

east Texas.

• Obtained in 1999 merger.
• Produces from the Cotton Valley, Travis Peak

and Pettit formations at 5,800’ to 9,500’.

• Includes 656 producing wells.
• 58.5 million barrels of oil equivalent reserves

at 12/31/02.
2002 Activity
• Drilled and completed 14 wells.
• Performed 33 well recompletion pro g r a m .
2003 Plans
• Complete 3 wells drilling in late 2002.
• Drill 13 wells.
• Recomplete 50 wells.

Groesbeck Area

Profile
• 80% average working interest in 140,000 acres

in east central Texas.

• Added acreage in 2002 acquisition.
• Produces from the Cotton Valley, Travis Peak
and Bossier formations at 6,000’ to 12,000’.

• Includes 493 producing wells.
• 31.3 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Drilled and completed 5 wells.
• Recompleted 5 wells.

2003 Plans
• Drill 12 wells.
• Initiate 30 well recompletion program.

Jonah/Corona

Profile
• 32% average working interest in 30,000 acres in

western Wyoming.

• Obtained in 2000 merger.
• Produces gas from the Lance formation at

7,500’ to 10,000’.

• 5.2 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Initiated drilling of 2 infill wells in the Jonah field.
• Initiated drilling of an exploratory well in the

Corona Exploration Unit.

2003 Plans
• Complete wells drilled in 2002.
• Evaluate additional drilling opportunities.

Washakie

Profile
• 76% average working interest in 210,000 acres

in southern Wyoming.
• Obtained in 2000 merger.
• Produces gas from multiple formations at

6,800’ to 10,300’.

• 67.2 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Drilled and completed 30 gas wells.
• Participated in 45 outside operated wells.
• Recompleted 7 gas wells.

8626pg024_28_04-11 6/21/04 12:20 PM Page 3

2003 Plans
• Drill 30 gas wells.
• Participate in 50 outside operated wells.
• Recomplete 11 gas wells.

2002 Activity
• Drilled and completed 43 development wells.
• Drilled and completed 9 exploratory wells.
• Acquired additional acreage and seismic.

Bluebell/Altamont

Profile
• 93% working interest in 52,000 acres in

northeastern Utah.

• Obtained in 1999 acquisition.
• P roduces premium priced yellow crude oil from
the Wasatch formation at 8,000’ to 15,000’.

• 10.6 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Completed 3 oil wells drilled in 2001.
• Performed 9 recompletions.
2003 Plans
• Recomplete 4 wells.
• Upgrade salt water disposal system.

NEBU/32-9 Units

Profile
• 25% working interest in 50,000 acres in the

San Juan Basin of northwestern New Mexico.

• Development began in the late 1980s and

early 1990s.

• Includes 168 coalbed methane wells, 154 con-

ventional wells, gas and water transmission systems
and an automated production control system.
• Produces primarily coalbed methane from the

Fruitland Coal formation at 3,000’.

• 25.7 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Recavitated 15 wells.
• Installed 4 pumping units for water removal.
• Drilled and completed 18 conventional gas wells.
• Received regulatory approval for downspacing

outside Fruitland Coal fairway.

2003 Plans
• Drill up to 6 infill coalbed methane wells.
• Recavitate 16 wells.
• Drill 30 conventional gas wells.

GULF
OF MEXICO

TEXAS

Gulf Coast

South Texas

Profile
• Up to 100% working interest in 669,000 acres.
• Obtained in 1999 acquisition & 2000 merger.
• Key areas include Zapata, Agua Dulce/

N. Brayton, Houston and Pettus/Ray Ranch.
• Produces oil and gas from the Frio/Vicksburg,
Yegua, Wilcox and Woodbine trends at 1,500’
to 15,000’.

• 28.5 million barrels of oil equivalent reserves

at 12/31/02.

2003 Plans
• Drill 40 to 50 development wells.
• Drill 5 to 10 exploratory wells.
• Acquire additional 3-D seismic.

TEXAS

LOUISIANA

GULF
OF MEXICO

Gulf Offshore – Shelf

West Cameron Miocene Trend

Profile
• Includes 5 blocks in the West Cameron Miocene

Trend area.

• Working interests range from 38% to 100%.
• Located offshore Louisiana in 60’ of water.
• Produces oil and gas from sands at 7,200’ to

14,300’.

• 1.6 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Completed geophysical analysis.
2003 Plans
• Drill exploratory well on West Cameron 181.
• Drill exploratory well on West Cameron 165.
• Drill exploratory well on West Cameron 198.
• Bring in industry partners.
• Pursue shallower development opportunities.

Main Pass/Viosca Knoll

Profile
• 50% to 52% working interest in 3 blocks in the

Main Pass area.

• 47% to 100% working interest in 3 blocks in the

Viosca Knoll area.

• Obtained in 2000 merger.
• Located off s h o re Louisiana in 120’ to 900’ of water.
• Viosca Knoll wells produce through Main Pass

facilities.

• Produces oil and gas from multiple sands at

7,900’ to 12,600’.

• 8.5 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Drilled and completed 1 well at Main Pass 259.
• Drilled and completed 1 well at Viosca Knoll 694.
• Completed previous discovery at Main Pass 20.
• Restored production at Viosca Knoll 738.
2003 Plans
• Initiate production at Main Pass 20.
• Drill 1 exploratory well in Main Pass area.
• Drill 1 exploratory well in Viosca Knoll area.
• Evaluate additional prospects.

South Marsh Island Area

Profile
• Includes 9 fields in the South Marsh Island Area.
• Working interests range from 17% to 100%.
• Obtained in 1999 acquisition.
• Located offshore Louisiana in 200’ of water.
• Produces oil and gas from sands at 3,900’ to

15,000’.

• 4.2 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Drilled and completed 3 wells at South Marsh

Island 128.

• Acquired 4-C 3-D seismic data over area.
2003 Plans
• Drill up to 3 wells at South Marsh Island 128.
• Initiate recompletion program at South Marsh

Island 23 & 128.

• Evaluate 4-C seismic survey.

West Cameron 4C Area

Profile
• Includes 17 offshore blocks where Devon is

applying 4-C seismic technology.

• Working interests range from 36% to 100%.
• Located offshore Louisiana in 200’ of water.
2002 Activity
• Drilled and completed 1 well at West Cameron 534.
• Drilled and completed 1 well at West Cameron 536.
• Drilled and completed 2 wells at West Cameron 532.
2003 Plans
• Drill 2 wells at West Cameron 575.
• Drill 2 or 3 additional wells.

High Island 582 (Cyrus)

Profile
• 37% working interest.
• Obtained in 1999 acquisition.
• Located offshore Texas in 440’ of water.
• Produces primarily gas from sands at 4,000’ to

12,000’.

• 5.9 million barrels of oil equivalent reserves at

12/31/02.
2002 Activity
• Completed construction and installation of

production facilities.

• Commenced oil and gas production from 4 wells.
2003 Plans
• Produce and monitor.
• Evaluate additional development potential.

Eugene Island 330 Area

Profile
• Includes 11 fields located in and around Eugene

Island 330.

• Working interests range from 23% to 100%.
• Obtained in 1999 acquisition & 2000 merger.
• Located off s h o re Louisiana in 250’ of water.
• P roduces oil and gas from sands at 1,200’

to 9,000’.

• 5.9 million barrels of oil equivalent reserves at

1 2 / 3 1 / 0 2 .
2002 Activity
• Drilled and completed 3 wells in the Eugene

Island 330 field.

• Drilled and completed 2 wells in the Eugene

Island 305 field.

• Upgraded water handling capacity at Eugene

Island 330.

• Upgraded production facilities at Eugene Island

305.
2003 Plans
• Drill 3 to 6 wells in the area.
• Initiate recompletion program in the Eugene

Island 330 field.

8626pg024_28_04-11 6/21/04 12:20 PM Page 4

Shelf Exploration Prospects

Deepwater Exploration Prospects

Northeast British Columbia

Profile

Grays

Profile

Tuscany East

• Galveston 424
• Located offshore Texas in 100’ of water.
• Target formation: Mid-Miocene sands at

10,000’ to 11,000’.
• 65% working interest.
• Net unrisked reserve potential: 7 million barre l s

• Desoto Canyon 180/224
• Located offshore Louisiana in 6,700’ of water.
• Target formation: Middle Miocene sands at

13,500’ to 15,000’.
• 25% working interest.
• Net unrisked reserve potential: 30 million barrels

of oil equivalent.

Puma

• East Cameron 333
• Located offshore Louisiana in 240’ of water.
• Target formation: Lower Pliocene sands at

19,000’ to 23,000’.
• 50% working interest.
• Net unrisked reserve potential: 6 million barre l s

of oil equivalent.

2003 Plans
• Finalize geophysical analysis and drilling

contracts.

• Bring in industry partners.
• Drill exploratory test wells.

TEXAS

LOUISIANA

of oil equivalent.

Sturgis

• Second well in ChevronTexaco joint venture.
• Atwater 182
• Located offshore Louisiana in 3,600’ of water.
• Target formation: Sub-salt structure in the

Atwater Fold Belt Trend at 26,500’.

• 25% working interest.
2003 Plans
• Receive final drilling permit approval.
• Drill exploratory test wells.

GULF
OF MEXICO

BRITISH
COLUMBIA

ALBERTA

Canada

Gulf Offshore – Deepwater

Green Canyon Complex

Profile
• 48% working interest in Green Canyon 112 &

113 (Angus Field).

Mackenzie Delta/Beaufort Sea

Profile
• 46% working interest in 3.2 million exploratory

acres in the Mackenzie Delta and shallow waters
of the Beaufort Sea.

• Devon is the largest holder of exploration

• 48% working interest in Green Canyon 155

acreage in this area.

Profile
• 75% average working interest in 2.4 million acres
in northwestern Alberta and northeastern British
Columbia.

• Key areas include Hamburg, Ladyfern, Wildmint,

Tommy Lakes and Wa rg e n .
• Primarily winter-only drilling.
• Produces oil and gas from multiple formations

including liquid-rich gas from the Slave Point at
8,000’ to 10,000’.

• 78.6 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Drilled and completed 9 Slave Point wells

including 5 wells at Ladyfern.

• Obtained pipeline capacity to bring Ladyfer n

wells online.

• Drilled and completed 16 Baldonnel wells at

Wargen.

• Drilled and completed 37 additional wells in

various other areas.

2003 Plans
• Drill 93 total wells, 60% exploratory.
• Drill 7 Slave Point wells at Hamburg and Ladyfern .
• Drill 6 Halfway formation wells at Tommy Lakes.
• Drill 6 Jean Marie formation wells at Peggo.
• Drill 25 wells at Ring Border.

Northern Plains

Profile
• 75% average working interest in 3.7 million acres

in north central Alberta.

• Key areas include Springburn, Hangingstone,

Woodenhouse, Goodfish, Kirby, Gift and Dawson.

• Primarily winter-only drilling.
• Produces shallow gas from multiple formations

at 1,000’ to 2,500’.

• Produces oil and gas from Devonian formations

at 6,000’ to 9,000’.

• 61.1 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Drilled and completed 112 of 127 wells.

2003 Plans
• Drill 25 shallow wells at Cherpeta.
• Drill 24 shallow wells at Springburn.
• Drill 10 wells at Kirkby.
• Drill 74 additional wells in various other areas.

Peace River Arch

Profile
• 74% average working interest in 1.5 million acres

(Manatee Field).

• Obtained in 2000 merger.
• 14.5 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Initiated production from 2 wells at Manatee.

2003 Plans
• Produce and monitor.

Cascade

Profile
• Walker Ridge 206
• 25% working interest.
• Located offshore Louisiana in 8,200’ of water.

2002 Activity
• Drilled discovery well.

2003 Plans
• Finalize follow-up well location with partners.
• Drill follow-up well.

• Onshore drilling limited to winter only.

in western Alberta.

2002 Activity
• Drilled the Tuk M-18 discovery well.
• Conducted 50 square mile onshore 3-D seismic
survey and 12 square mile 2-D seismic survey.
• Conducted 42 square mile offshore 3-D seismic

survey.

• Consolidated offshore licenses into one large

license.

2003 Plans
• Drill 2 exploratory wells.
• Evaluate offshore seismic and pursue farm-out

opportunities.

• Prepare to secure space on the proposed

Mackenzie Valley pipeline.

• Key areas include Girouxville, Dunvegan
Eaglesham, Pouce Coupe and Valhalla.

• Produces liquids-rich gas and light gravity oil
from multiple formations at 4,500’ to 8,000’.
• 104.5 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Drilled and completed 71 wells.
• Placed 5,000 barrels per day oil battery on-

stream at Girouxville.

• Performed recompletion program at Eaglesham.

2003 Plans
• Drill 71 total wells, 88% exploratory.
• Drill 8 infill wells at Dunvegan.
• Drill 16 wells at Valhalla and Pouce Coupe.

8626pg024_28_04-11 6/21/04 12:20 PM Page 5

Deep Basin

Profile
• 48% average working interest in 1.7 million

acres in western Alberta.

• Key areas include Wapiti, Elmworth, Bilbo,

Pinto/Leland and Hiding.

• Produces liquids-rich gas from Cretaceous and

Devonian formations at 3,000’ to 13,500’.

• 68.0 million barrels of oil equivalent reserves at

12/31/02.

2002 Activity
• Drilled and completed 56 of 60 wells.
• Increased gas production 27%.
• Placed production facility on stream at Elmworth.
2003 Plans
• Drill 98 total wells, 50% exploratory.
• Drill 24 wells at Pinto/Leland.
• Drill 25 wells at Bilbo.
• Expand production facilities at Elmworth and

International

Leland.

Foothills

Azerbaijan

South Atlantic Margin

Profile
• 53% working interest in 1.2 million acres in

western Alberta and eastern British Columbia.
• Key exploratory areas include Grizzly Valley in
eastern British Columbia, Narraway, Cabin
Creek and Findley in west central Alberta and
Moose in southern Alberta.

• High-impact, long-lived reserves.
• Produces gas from multiple formations at 4,000’

to 15,000’.

Profile
• 5.6% carried interest in 137,000 acres in the

Profile
• 2.7 million net acres in 4 licensed blocks

Azeri-Chirag-Gunashli (ACG) oil fields
offshore Azerbaijan.

• Operating and capital cost currently paid by
partners under carried interest agreement.
• Initial position obtained in 1999 acquisition.
• Oil is exported by pipeline to the west and north.
• Anticipate significant production and revenue

offshore West Africa:

Keta block offshore Ghana; 56% interest.
Agali block offshore Gabon; 50% interest.
Kowe block off s h o re Gabon; 19% intere s t .
Marine IX block offshore Congo; 47%
interest.

• 624,000 net acres in 2 licensed blocks

to Devon commencing in 2009.

offshore Brazil:

• 79.1 million barrels of oil equivalent reserves at

• 125.1 million barrels of oil equivalent reserves

12/31/02.

at 12/31/02.

• Drilled 6 of 12 pre-drill wells for the Azeri

• 4.9 million barrels of oil equivalent reserves

2002 Activity
• Drilled and completed 27 of 30 gas wells.
• Drilled 2 successful exploratory wells in the

Grizzly Valley area.

• Commenced operations of 135 million cubic

feet of gas per day sweet gas processing plant
at Narraway.

• Initiated production from the Grizzly Valley area

at 10 million cubic feet of gas per day,
previously limited by facilities.

2003 Plans
• Drill 34 total wells, 75% exploratory.
• Drill up to 8 wells at Grizzly Valley.
• Increase production from Grizzly Valley area to

35 million cubic feet of gas per day as
facilities are expanded.

2002 Activity
• Drilled 2 extended reach wells from the

Chirag platform.

platform.

• Acquired 4-C 3-D seismic survey over the

Azeri and Chirag portions of the field.
• Began construction on phase 1 field

development.

• Sanctioned phase 2 field development.
• Received approval for and commenced

construction of the main export pipeline from
Baku to Ceyhan, Turkey.

2003 Plans
• Drill 1 extended reach well from the Chirag

• Drill at least 20 wells at Findley, Narraway and

platform.

Bighorn.

• Evaluate gas potential at Moose.

• Drill remaining 6 pre-drill wells for the Azeri

platform.

Heavy Oil

• Expand fluid handling facilities.
• Commence pre-drill operations on the phase

Profile
• 95% average working interest in 1.8 million acres

in northeastern Alberta.

• Key areas include Manatokan, Lloydminster,

D o v e r, Jackfish and Surmont.

• A c reage contains prospects suitable for both

conventional and thermal re c o v e r y.

• 64.2 million barrels of oil equivalent reserves at

1 2 / 3 1 / 0 2 .

2002 Activity
• Drilled and completed 215 Lloydminster

conventional heavy oil wells.

• Drilled 88 delineation wells at Trout, Jackfish and

S u r m o n t .

2003 Plans
• Drill 134 Lloydminster conventional heavy oil wells.
• Drill 80 delineation wells at Jackfish and 2

horizontal well pairs at Dover.

• Investigate new solvent recovery technologies in

thermal are a s .

• Participate in phase 1 development of Surmont

p ro j e c t .

2 Azeri platform.

• Continue construction of main export pipeline.

China

Profile
• 1.9 million net acres in 4 licensed blocks in
the Pearl River Mouth Basin offshore China.

• Located in 300’ of water.
• Initial position obtained in 2000 merger.
• Includes 1998 and 1999 Panyu oil discoveries.
• 17.8 million barrels of oil equivalent reserves

at 12/31/02.

2002 Activity
• Continued construction of 2 separate Panyu

drilling and production facilities.

• Continued construction of 1 million barrel
floating production, storage and offloading
vessel (FPSO).

2003 Plans
• Finish construction and installation of Panyu

facilities.

• Commission FPSO.
• Drill 15 development Panyu wells with first

production scheduled for late 2003.
• Drill 1 exploratory well on block 16/02.

BM-BAR-3 block; 100% interest.
BM-C-8 block; 45% interest.

• Obtained initial positions in 1999 acquisition

and 2000 merger.

• Interest in 7 producing oil wells on the Kowe

block.

at 12/31/02.

2002 Activity
• Installed 27-mile oil export pipeline to replace
floating storage and offloading vessel on the
Kowe block.

• Installed sour crude facilities to initiate Azile
formation development on the Kowe Block.
• I n t e r p reted 3-D seismic data on the Keta and

Agali blocks.

• Aw a rded deepwater block BM-BAR-3.

2003 Plans
• Drill development well on the Kowe block.
• A c q u i re 3-D seismic survey on Kowe block.
• Drill deepwater exploratory well on the Keta

b l o c k .

8626pg024_28_04-11 6/21/04 12:20 PM Page 6

Featured employees clockwise, from upper left: Michel Scott, Calgary; Marvinette Ponder, Brandon McGinley,
Jaren Howard and Jennifer Day, Oklahoma City; and Kenneth Walker, Bridgeport.

8626pg029_100_04-11 6/21/04 12:26 PM Page 29

FINANCIAL STATEMENTS AND MANAGEMENT’S
DISCUSSION AND ANALY S I S

Selected 11-Year Financial Data

32 Management’s Discussion and Analysis of Financial Condition

and Results of Operations

59 Management’s Responsibility for Financial Statements

Independent Auditors’ Report

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

T O TAL REVENUES
($ billions)

4.4

2.9

2.6

1.2

0.6

C A P I TAL EXPENDITURES FOR
E X P L O R ATION AND DEVELOPMENT
($ billions)

STOCKHOLDERS’ EQUITY
($ billions)

4.7

1.5

1.3

0.8

0.5

3.3

2.5

0.8

8626pg029_100_04-11 6/21/04 12:26 PM Page 30

SELECTED 11-YEAR FINANCIAL DATA (1)

1992

1993

1994

1995

OPERATING RESULTS (IN MILLIONS, EXCEPT PER SHARE DATA)

Revenues (Net of royalties):

Oil sales
Gas sales
Natural gas liquids sales
Marketing & midstream revenues
Other income

Total revenues

Production and operating expenses
Marketing & midstream operating costs and expenses
Depreciation, depletion and amortization of

property and equipment
Amortization of goodwill (2)
General and administrative expenses
Expenses related to mergers
Interest expense (3)
Foreign exchange effect
Change in fair value of financial instruments
Reduction of carrying value of oil and gas properties
Impairment of ChevronTexaco Corporation common stock
Income tax expense (benefit)

Total expenses

Net earnings (loss) before minority interest, cumulative effect of
change in accounting principle and discontinued operations (4)

Net earnings (loss)
Preferred stock dividends
Net earnings (loss) to common shareholders

Net earnings (loss) per common share:

Basic
Diluted

Weighted average shares outstanding:

Basic
Diluted

BALANCE SHEET DATA (IN MILLIONS)

Total assets
Debentures exchangeable into shares of

ChevronTexaco Corporation common stock (5)

Other long-term debt (6)
Deferred income taxes
Stockholders’ equity
Common shares outstanding

$
$
$
$
$

$
$

$
$
$
$
$
$
$
$
$
$

$
$
$
$

$
$

$
$
$
$

367
131
8
-
11

517

203
-

147
-
43
-
51
-
-
-
-
19

463

54
11
6
5

355
189
13
-
31

588

227
-

170
-
51
11
42
-
-
180
-
(68)

613

(25)
(55)
7
(62)

0.14
0.13

(1.27)
(1.27)

39
42

49
49

351
171
13
-
14

549

218
-

149
-
45
7
29
-
-
22
-
25

495

54
54
11
43

0.84
0.84

51
54

419
157
15
-
35

626

222
-

160
-
43
-
39
-
-
97
-
19

580

46
55
15
40

0.76
0.76

52
53

1,464

1,336

1,475

1,639

-
571
52
503
48

-
508
-
472
49

-
457
30
688
52

-
565
48
739
52

Includes distributions on preferred securities of subsidiary trust of $5, $10, $10 and $7 million in 1996, 1997, 1998 and 1999, respectively.

(1) All of the years shown exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002.
(2) Amortization of goodwill in 1999, 2000 and 2001 resulted from Devon's 1999 acquisition of PennzEnergy. As of January 1, 2002, goodwill is no longer amortized.
(3)
(4) Before minority interest in Monterrey Resources, Inc. of ($1) and ($5) million in 1996 and 1997, respectively: and
the cumulative effect of change in accounting principle of ($1) and $49 million in 1993 and 2001, respectively
and the results of discontinued operations of ($43), ($29), $0, $9, $15, $13, ($35), $39, $69, $31 and $45 million in 1992 through 2002, respectively.
(5) Devon beneficially owns approximately 7 million shares of ChevronTexaco Corporation common stock. These shares have been deposited with an

exchange agent for possible exchange for $760 million principal amount of exchangeable debentures. The ChevronTexaco shares and debentures were
acquired through the August 1999 merger with PennzEnergy.
Includes preferred securities of subsidiary trust of $149 million in years 1996, 1997 and 1998.

(6)
NM Not a meaningful number.

1.
1.

2,2

1,1

19
57
15
-
35

22
-

60
-
43
-
39
-
-
97
-
19

46
55
15
40

76
76

52
53

-
65
48
39
52

8626pg029_100_04-11 6/21/04 12:26 PM Page 31

1996

1997

1998

1999

2000

2001

2002

5-YEAR
GROWTH RATE

10-YEAR
GROWTH RATE

529
211
29
-
36

805

271
-

175
-
57
-
59
-
-
-
-
106

668

137
151
47
104

497
367
36
10
42

952

288
4

268
-
56
-
51
6
-
633
-
(128)

236
335
25
8
22

626

231
3

212
-
48
13
53
16
-
354
-
(103)

436
616
68
20
10

906
1,474
154
53
40

784
1,878
131
71
69

909
2,133
275
999
34

1,150

2,627

2,933

4,350

328
10

379
16
83
17
122
(13)
-
476
-
(75)

544
28

662
41
96
60
155
3
-
-
-
377

666
47

831
34
114
1
220
11
2
979
-
5

886
808

1,211
-
219
-
533
(1)
(28)
651
205
(193)

1,178

827

1,343

1,966

2,910

4,291

(226)
(218)
12
(230)

(201)
(236)
-
(236)

(193)
(154)
4
(158)

1.97
1.92

(3.35)
(3.35)

(3.32)
(3.32)

(1.68)
(1.68)

53
56

69
75

71
77

94
99

661
730
10
720

5.66
5.50

127
132

23
103
10
93

0.73
0.72

128
130

59
104
10
94

0.61
0.61

155
156

2,242

1,965

1,931

6,096

6,860

13,184

16,225

-
511
136
1,160
63

-
576
50
1,006
71

-
885
15
750
71

760
1,656
313
2,521
126

760
1,289
634
3,277
129

649
5,940
2,149
3,259
126

662
6,900
2,627
4,653
157

13%
42%
50%
151%
(4%)

36%

25%
189%

35%
NM
31%
NM
60%
(170%)
NM
1%
NM
9%

30%

NM
NM
(4%)
NM

NM
NM

18%
16%

53%

NM
64%
121%
36%
17%

10%
32%
42%
NM
12%

24%

16%
NM

24%
NM
18%
NM
26%
NM
NM
NM
NM
NM

25%

1%
25%
5%
34%

16%
17%

15%
14%

27%

NM
28%
48%
25%
13%

8626pg029_100_04-11 6/21/04 12:26 PM Page 32

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

On January 24, 2002, we completed our acquisition of Mitchell Energy & Development Corp. (“Mitchell”).
Under the terms of this agreement, 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 billion senior unsecured term loan credit facility. The Mitchell merger added approximately
404 million Boe to our proved reserves.

Following the Mitchell announcement in August 2001, we announced on September 4, 2001, that we 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 our 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 these mergers and acquisitions, exploration and development efforts have also been significant

contributors to our growth. In 2002, we spent $1.5 billion for exploration, drilling and development. 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 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 our 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. It 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%.

During 2002, we marked our 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 our 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. Our future growth, if any, will depend on our ability to continue to add
reserves in excess of production.

8626pg029_100_04-11 6/21/04 12:26 PM Page 33

Oil, gas and NGL prices are influenced by many factors outside of our control. As a result, Devon’s management has
focused its efforts on increasing oil and gas reserves and production and controlling expenses. Over our 14-year history as
a public company, Devon has been able to reduce controllable operating costs per unit of production. Devon’s future
earnings and cash flows are dependent on our 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.)

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

2002

42
761
19
188

21.71
2.80
14.05
17.61

909
2,133
275
3,317

2002

24
482
14
118

21.99
2.91
13.37
17.87

524
1,403
192
2,119

$
$
$
$

TOTAL
YEAR ENDED DECEMBER 31,
2001

2001 vs 2000

2002 vs 2001

+17%
+56%
+138%
+50%

+1%
-27%
-17%
-21%

+16%
+14%
+110%
+19%

36
489
8
126

21.41
3.84
16.99
22.19

784
1,878
131
2,793

-3%
+17%
+14%
+12%

-14%
+9%
-19%
-1%

-13%
+27%
-15%
+10%

DOMESTIC
YEAR ENDED DECEMBER 31,
2001

2001 vs2000

2002 vs2001

-8%
+28%
+133%
+24%

-2%
-30%
-22%
-25%

-11%
-11%
+86%
-6%

26
376
6
95

22.36
4.17
17.15
23.80

586
1,571
103
2,260

-10%
+6%
+0%
+1%

-12%
+14%
-16%
+4%

-19%
+20%
-24%
+4%

2000

37
417
7
113

24.99
3.53
20.87
22.38

906
1,474
154
2,534

2000

29
355
6
94

25.45
3.67
20.30
22.95

727
1,305
136
2,168

8626pg029_100_04-11 6/21/04 12:26 PM Page 34

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

2002

16
279
5
68

21.00
2.62
15.93
16.96

331
730
83
1,144

2002

2
--
--
2

23.70
--
--
23.70

54
--
--
54

$
$
$
$

CANADA
YEAR ENDED DECEMBER 31,
2001

2001 vs2000

2002 vs 2001

+100%
+147%
+150%
+134%

+18%
-4%
-3%
+1%

+127%
+138%
+196%
+138%

8
113
2
29

17.84
2.73
16.43
16.80

146
307
28
481

+60%
+82%
+100%
+81%

-27%
+1%
-38%
-12%

+26%
+82%
+56%
+59%

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2001

2001 vs 2000

2002 vs2001

+0%
NM
NM
+0%

+1%
NM
NM
+1%

+4%
NM
NM
+4%

2
--
--
2

23.42
--
--
23.42

52
--
--
52

-33%
NM
NM
-33%

+9%
NM
NM
+9%

-17%
NM
NM
-17%

2000

5
62
1
16

24.46
2.71
26.51
19.18

116
169
18
303

2000

3
--
--
3

21.44
--
--
21.44

63
--
--
63

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.

WITH HEDGES
2001

2002

2000

WITHOUT HEDGES
2001

2000

2002

Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe)

$
$
$
$

21.71
2.80
14.05
17.61

21.41
3.84
16.99
22.19

24.99
3.53
20.87
22.38

$
$
$
$

22.63
2.70
14.05
17.36

21.79
3.89
16.99
22.48

26.00
3.61
20.87
23.01

8626pg029_100_04-11 6/21/04 12:26 PM Page 35

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
p roduction from Devon’s other properties declined four million barrels. This reduction was primarily the result of domestic and
i n t e rnational properties that 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 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 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
our domestic properties increased 21 Bcf, due primarily to drilling and development in our 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 that accounted for substantially all of
the increase.

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 36

Operating Costs and Expenses The details of the changes in operating costs and expenses between 2000 and 2002

are shown in the table below.

2002

2002 vs2001

2001

2001 vs 2000

2000

YEAR ENDED DECEMBER 31,

Absolute (in millions):

Production and operating expenses:

Lease operating expenses
Transportation costs
Production taxes

Depreciation, depletion and amortization of

oil and gas properties
Amortization of goodwill

Subtotal

Marketing and midstream operating costs and

expenses

Depreciation and amortization of non-oil

and gas properties

General and administrative expenses
Expenses related to mergers
Reduction of carrying value of oil and gas pro p e r t i e s

Total

Operating costs and expenses per Boe:
Production and operating expenses:

Lease operating expenses
Transportation costs
Production taxes

Depreciation, depletion and amortization of

oil and gas properties
Amortization of goodwill

Subtotal

Marketing and midstream operating costs and

expenses ( 1 )

Depreciation and amortization of non-oil

and gas properties ( 1 )

General and administrative expenses ( 1 )
Expenses related to mergers ( 1 )
Reduction of carrying value of oil and gas pro p e r t i e s ( 1 )

Total

621
154
111

1,106
--
1,992

+33%
+86%
-4%

+39%
-100%
+33%

808

+1,619%

105
219
--
651
3,775

3.30
0.82
0.59

5.88
--
10.59

+176%
+92%
-100%
-34%
+41%

-11%
+24%
-36%

-7%
-100%
-11%

4.29

+1,059%

0.55
1.16
--
3.45
20.04

+83%
+27%
-100%
-56%
-6%

467
83
116

793
34
1,493

38
114
1
979
2,672

3.71
0.66
0.92

6.30
0.27
11.86

0.37

0.30
0.91
0.01
7.78
21.23

+20%
+57%
+13%

+25%
-17%
+23%

+68%

+27%
+19%
-98%
NM
+87%

+8%
+40%
+1%

+13%
-27%
+10%

+48%

+11%
+7%
-98%
NM
+68%

388
53
103

632
41
1,217

30
96
60
--
1,431

3.43
0.47
0.91

5.58
0.37
10.76

0.25

0.27
0.85
0.53
--
12.66

( 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.
NM – Not meaningful.

Oil, Gas and NGL Production and Operating Expenses The details of the changes in production and operating

expenses related to oil, gas and NGL producing activities between 2000 and 2002 are shown in the table below.

2002

2002 vs2001

2001

2001 vs2000

2000

YEAR ENDED DECEMBER 31,

Expenses ($ in millions):

Lease operating expenses
Transportation costs
Production taxes

Total production and operating expenses

Expenses per Boe:

Lease operating expenses
Transportation costs
Production taxes

Total production and operating expenses

621
154
111
886

3.30
0.82
0.59
4.71

+33%
+86%
-4%
+33%

-11%
+24%
-36%
-11%

467
83
116
666

3.71
0.66
0.92
5.29

+20%
+57%
+13%
+22%

+8%
+40%
+1%
+10%

388
53
103
544

3.43
0.47
0.91
4.81

8626pg029_100_04-11 6/21/04 12:26 PM Page 37

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 our 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 an 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 Rocky Mountain and Permian Basin areas,
which have higher production tax rates than the other domestic areas.

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 depletable base. The
depletable base is the net capitalized investment in those reserves, including estimated future development and
dismantlement and abandonment costs. 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 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 NGL 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 NGL 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 38

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 which we operate. 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 and production activities, as well as marketing and midstream activities. See the following table for a summary
of G&A expenses by component.

Gross G&A
Capitalized G&A
Reimbursed G&A
Net G&A

2002

2002 vs2001

2001

2001 vs 2000

2000

YEAR ENDED DECEMBER 31,

(IN MILLIONS)

387
(97)
(71)
219

+56%
+26%
+25%
+92%

248
(77)
(57)
114

+19%
+24%
+12%
+19%

209
(62)
(51)
96

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
properties we operate. Changes in both the capitalized and reimbursed amounts were primarily related to the Anderson and
Mitchell acquisitions.

2001 vs. 2000 G ross G&A increased $39 million primarily due to additional costs incurred as a result of the Anderson
acquisition and other personnel related costs. G&A was reduced $15 million due to an increase in the amount capitalized. The
i n c rease 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
p roperties. The increase in reimbursed G&A was primarily related to an increase in the number of operated pro p e r t i e s .

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 were primarily 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 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. We do 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.

A writedown is not required 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 is also
not required if the value of additional reserves proved up on properties after the end of the quarter but prior to the
publishing of the financial statements would result in the ceiling exceeding the costs to be recovered, as long as the
properties were owned at the end of the quarter.

An expense recorded in one period may not be reversed in a subsequent period. This is true even though higher oil

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

During 2002 and 2001, we reduced the carrying value of our oil and gas properties by $651 million and $883 million,
respectively, due to 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 39

United States
Canada

Total

YEAR ENDED DECEMBER 31,

2002

2001

GROSS

NET OF TAXES

GROSS

NET OF TAXES

(IN MILLIONS)

--
651
651

--
371
371

449
434
883

281
252
533

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. We estimate
such fair value using our 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. These prices 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, our Canadian costs to be recovered

exceeded their related ceiling value by $371 million. This after-tax amount resulted in a pre-tax reduction of the carrying
value of our 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.This 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. These values 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, we elected to abandon operations in Thailand, Malaysia, Qatar and certain properties in
Brazil. After meeting the drilling and capital commitments on these properties, we determined these properties did not meet
our 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.

E ffective January 1, 2002, Devon was re q u i red to adopt the provisions of SFAS No. 144, Accounting for the Impairm e n t

or Disposal of Long-Lived Assets. The provisions of SFAS No. 144 only apply pro s p e c t i v e l y. As a result, these impairment
c h a rges have not been reclassified as part of the Discontinued Operations on the consolidated statements of operations.

Other Income (Expenses) The details of the changes in other income (expenses) between 2000 and 2002 are shown

in the table below.

Other income (expenses):

Interest expense:

2002

2001

2000

(IN MILLIONS)

Interest based on debt outstanding
(Accretion) amortization of debt (discount) premium, net
Facility and agency fees
Amortization of capitalized loan costs
Capitalized interest
Early retirement premiums
Other

Total interest expense

Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Impairment of ChevronTexaco Corporation common stock
Other income
Total

(499)
(13)
(2)
(8)
4
(8)
(7)
(533)
1
28
(205)
34
(675)

(200)
(10)
(1)
(3)
3
(7)
(2)
(220)
(11)
(2)
--
69
(164)

(157)
4
(3)
(2)
3
--
--
(155)
(3)
--
--
40
(118)

8626pg029_100_04-11 6/21/04 12:26 PM Page 40

Interest Expense 2002 vs. 2001 Interest expense increased $313 million in 2002. An increase in the average debt
balance outstanding from $3 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% 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 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.

The increase in accretion of debt discounts in 2001 was related to the adoption of 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 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 incre a s e
or decrease the expected amount of Canadian dollars eventually re q u i red to repay the notes. Such changes in the Canadian
dollar equivalent balance of the debt are re q u i red 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 fro m
$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 re t i red prior to maturity. The Canadian-to-U.S. dollar exchange rate
d ropped slightly in January prior to the debt re t i rement. 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, we record in our statements of operations the
change in fair value of derivative instruments that do not qualify for hedge accounting treatment.

During 2002 and 2001, we 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. We also 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. We
acquired these shares in our 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 PennzEnergy acquisition.

8626pg029_100_04-11 6/21/04 12:26 PM Page 41

We 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, the length of time the
stock price has been below original cost and the performance of the stock price in relation to its competitors within the
industry. Other factors include the market in general and whether the decline is attributable to specific adverse conditions
affecting ChevronTexaco.

Beginning in July 2002, the market value of Chevro n Texaco 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.
It declined further to $66.48 per share at December 31, 2002. The year-end price of $66.48 re p resents 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, we determined that the decline is other than temporary, as defined by accounting
rules. There f o re, the $205 million cumulative decrease in the value of the Chevro n Texaco common shares from the initial
acquisition in August 1999 to December 31, 2002, was re c o rded as a noncash charge to our results of operations in the
fourth quarter of 2002. Net of the applicable tax benefit, the charge reduced our net earnings by $128 million.

Depending on the future performance of ChevronTexaco’s common stock, we may be required to record additional

noncash charges in future periods if we determine 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 we entered into 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 2002 vs. 2001 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.

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. It 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 42

Under the provisions of SFAS No. 144, we reclassified our 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:

Net gain on sale of discontinued operations
Earnings from discontinued operations before

income taxes
Income tax expense

Net results of discontinued operations

2002

2001
(IN MILLIONS)

23
9

56
25

2000

104
35

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 development of oil and gas properties) and 2000 total expenditures of
$1.1 billion ($1 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, we re p u rchased 3,754,000 shares of common stock at an aggregate cost of $190 million or $50.71 per

s h a re. We also re p u rchased shares of our common stock in 2001 under an odd-lot re p u rchase program. Pursuant to this
p rogram, Devon purchased and re t i red 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 our control and are difficult to predict.

8626pg029_100_04-11 6/21/04 12:26 PM Page 43

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.

Oil production (MMBbls)

2003
2004

Natural gas production (Bcf)

2003
2004

FIXED-PRICE PHYSICAL
DELIVERY CONTRACTS

PRICE SWAP
CONTRACTS

PRICE
COLLARS

TOTAL

--
--

16
16

--
--

35
--

20
1

239
47

20
1

290
63

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 our oil and natural gas production, Devon has mitigated, but not

eliminated, the potential negative effect of declining prices on our 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.

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, we 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. We currently intend 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”). We 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.

We 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. The final installment is 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 44

Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that we may elect for periods

up to six months. Devon has historically elected a rate that is based upon LIBOR, plus a margin dictated by our 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 our 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. We had no commercial paper debt
outstanding at December 31, 2002.

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:

April 15, 2006
October 15, 2006

(IN MILLIONS)

335
800
1,135

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 our
debt rating. Based on our 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 Corporation common stock. Also, total
capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling property impairments or
goodwill impairments. As of December 31, 2002, our ratio of total funded debt to total capitalization, as defined in its credit
agreements, was 55.0%.

Our access to funds from our 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 our Credit Facilities and the $3
billion term loan credit facility include covenants that require us 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
p roceeds 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
s u b o rdinated notes due June 15, 2007. The notes were redeemed at 104.375% of principal, or approximately $183 million.

8626pg029_100_04-11 6/21/04 12:26 PM Page 45

Debt Ratings

We receive 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 and near-term and long-
term production growth opportunities. Other considerations include 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 us to provide cash collateral in
situations where our liability under the hedge is above a certain dollar threshold and where our 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. 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.

Long-term debt
Operating leases
Drilling obligations
Firm transportation agreements

Total

PAYMENTS DUE BY YEAR

2003

2004

2005

2006

2007

(IN MILLIONS)

AFTER
2007

TOTAL

--
30
151
97
278

336
33
34
83
486

347
28
37
61
473

1,262
24
1
52
1,339

--
20
--
45
65

5,725
86
--
221
6,032

7,670
221
223
559
8,673

Firm transportation agreements represent “ship or pay” arrangements whereby Devon has committed to ship certain

volumes of gas for a fixed transportation fee. We have entered into these agreements to aid us in moving our 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 our 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 these items 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

8626pg029_100_04-11 6/21/04 12:26 PM Page 46

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 sheet.

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. Our 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. We believe 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 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. We 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.

We believe that our 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. 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, we 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. We 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 our 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 pro p e r t i e s .

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.

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The passage of time provides more qualitative information re g a rding 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 re s e r v e s
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 our 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.

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. On any particular day at the end of a quarter, prices can
be either substantially higher or lower than Devon’s long-term price forecast that is a barometer for true fair value. Oil and
gas property writedowns that result from applying the full cost ceiling limitation are caused by fluctuations in price. Such
writedowns do not indicate reductions to the underlying quantities of reserves and should not be viewed as absolute
indicators of a reduction of the ultimate value of the related reserves.

We recorded writedowns to our 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.

We also recorded writedowns to our 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 our 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 our current borrowing rates under our 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 our 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 We have 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.
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, accounting for goodwill 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.

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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.

Our 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 our 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 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.

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 our estimated
fair value of the marketing and midstream facilities and equipment.

Valuation of Goodwill Effective January 1, 2002, we 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. These include 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

8626pg029_100_04-11 6/21/04 12:26 PM Page 49

value of the obligation. This is 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. Also, 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.
S FAS No. 146 re q u i res that a liability for a cost associated with an exit or disposal activity be recognized when the
liability is incurred. Pre v i o u s l y, 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.

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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. We own no interests in variable interest entities, and therefore this new interpretation will
not affect our 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 and drilling risks. Risks also
include 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 our control and
are difficult to predict. In addition to volatility in general, our 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 our 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.

Though we have 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.

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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:

United States
Canada
International

(MMBBLS)

19.1 to 20.1
13.5 to 14.2
2.8 to 2.9

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.

United States
Canada
International

EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE

($3.00) to ($2.00)
($6.25) to ($4.25)
($2.80) to ($1.80)

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
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, we have aggregated costless collars as of January 31, 2003, 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.

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

BBLS/DAY

WEIGHTED AVERAGE
FLOOR
PRICE PER
BBL

CEILING
PRICE PER
BBL

MONTHS OF
PRODUCTION

United States ($20.00 - $22.75/$27.05 - $28.65)
United States ($23.25 - $23.50/$28.25 - $30.00)
United States ($23.50 - $23.50/$28.25 - $30.75)
Canada ($20.00 - $21.00/$26.60 - $28.15)
Canada ($22.00 - $22.75/$27.00 - $28.40)
Canada ($23.25 - $23.50/$28.35 - $29.25)
Canada ($23.50 - $23.50/$28.80 - $29.75)

18,000
8,000
6,000
5,000
13,000
5,000
3,000

$
$
$
$
$
$
$

21.65
23.38
23.50
20.40
22.29
23.30
23.50

$
$
$
$
$
$
$

27.91
29.12
29.31
27.37
27.52
28.79
29.18

Jan – Dec
Jan – Dec
Jul – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Jul – Dec

Gas Production We expect our 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:

United States
Canada

(BCF)

472 to 495
259 to 272

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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.

United States
Canada
Canada

MCF/DAY

PRICE/MCF

MONTHS OF
PRODUCTION

97,148
43,578
43,578

$ 3.23
$ 2.30
$ 2.29

Jan – Dec
Jan – Jun
Jul – Dec

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.

EXPECTED RANGE OF GAS PRICES
LESS THAN NYMEX PRICE

United States
Canada

($0.80) to ($0.30)
($0.90) to ($0.40)

Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2003 natural gas
p roduction that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the
floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the diff e rence. 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 our 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.

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

MMBTU/DAY

United States ($3.28 - $3.28/$6.23 - $6.53)
United States ($3.28 - $3.28/$5.53 - $5.93)
United States ($3.25 - $3.28/$4.65 - $4.93)
United States ($3.00 - $3.28/$4.05 - $4.20)
United States ($3.28 - $3.45/$4.20 - $4.49)
United States ($3.44 - $3.44/$6.69 - $6.69)
Canada ($3.28 - $3.39/$6.85 - $7.13)
Canada ($3.38 - $3.57/$6.10 - $6.89)
Canada ($3.45 - $3.52/$4.27 - $4.89)
Canada ($3.66 - $3.67/$7.24 - $7.68)
Canada ($3.53 - $3.54/$5.27 - $5.96)

40,000
55,000
70,000
130,000
110,000
5,000
20,000
80,000
90,000
30,000
40,000

WEIGHTED AVERAGE
FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

MONTHS OF
PRODUCTION

$
$
$
$
$
$
$
$
$
$
$

3.28
3.28
3.27
3.12
3.35
3.44
3.34
3.49
3.48
3.66
3.54

$
$
$
$
$
$
$
$
$
$
$

6.38
5.74
4.80
4.11
4.37
6.69
6.99
6.52
4.34
7.44
5.60

Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Apr – Sep
Jan – Dec
Jan – Dec
Jan – Dec
Apr – Oct
Jan – Dec

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:

United States
Canada

(MMBBLS)

16.6 to17.4
4.3 to 4.5

8626pg029_100_04-11 6/21/04 12:26 PM Page 53

Marketing and Midstream Revenues and Expenses D e v o n ’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, pro v i s i o n s
of the agreements, and the amount of repair and workover activity re q u i red 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 uncertainties, we estimate 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 and transportation costs will be between $141 million and $150 million. We estimate that 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 is 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 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. We can only marginally influence the prices we 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 that affect interest expense, such as the amount and timing of capital expenditures, are within
Devon’s control.

8626pg029_100_04-11 6/21/04 12:26 PM Page 54

Assuming no changes in fixed-rate debt balances during 2003, our 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. Our floating rate debt is discussed in the following paragraphs.

As of January 31, 2003, Devon had $1.1 billion outstanding under its original $3 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:

April 15, 2006
October 15, 2006

(IN MILLIONS)

335
800
1,135

This $3 billion facility includes various rate options that 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.

We also borrow under a $150 million Canadian dollar letter of credit facility that is primarily used to issue letters of cre d i t

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 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.

Our 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. We
expect between $10 million and $20 million of such items to be included in our 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
p revailing 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 re c o v e red”), 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 re c o v e red are compared to the ceiling on a quarterly basis. If the costs to be re c o v e re d
exceed the ceiling, the excess is written off as an expense. An expense re c o rded 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. Oil and gas
property writedowns that result from applying the full cost ceiling limitation are caused by fluctuations in price. Such
writedowns do not indicate reductions to the underlying quantities of reserves and should not be viewed as absolute
indicators of a reduction of the ultimate value of the related reserves.

8626pg029_100_04-11 6/21/04 12:26 PM Page 55

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 Our 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 re q u i red 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 re c o rded 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 re c o rd 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.

Other Revenues Devon’s other revenues in 2003 are expected to be between $23 million and $26 million.

Income Ta x e s D e v o n ’s financial income tax rate in 2003 will vary materially depending on the actual amount of financial
p re-tax earnings. The tax rate for 2003 will be significantly affected by the proportional share of consolidated pre-tax earn i n g s
generated by U.S., Canadian and International operations due to the diff e rent tax rates of each country. There are certain tax
deductions and credits that will have a fixed impact on 2003’s income tax expense re g a rdless of the level of pre-tax earnings that
a re 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 deferre d
income tax rate is expected to be between 20% and 30%. Significant changes in estimated capital expenditures, pro d u c t i o n
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 $465 million and $535 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/re w a rd projects and between $435 million and $510 million for new,
higher risk/re w a rd projects. Low risk/re w a rd projects include development drilling that does not offset currently pro d u c t i v e
units and for which there is not a certainty of continued production from a known productive formation. Higher risk/re w a rd
p rojects 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.

Related to Proved Reserves
Lower Risk/Reward Projects
Higher Risk/Reward Projects

Total

UNITED STATES

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

$330-$370
$335-$375
$180-$210
$845-$955

$105-$125
$150-$180
$205-$235
$460-$540

$30-$ 40
$ 0-$
0
$50-$ 65
$80-$105

$ 465-$ 535
$ 485-$ 555
$ 435-$ 510
$1,385-$1,600

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. We also expect 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 56

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.

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 Our major market risk exposure is in the pricing applicable to our 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 NGLs production. Pricing for oil and gas production has been volatile
and unpredictable for several years.

Devon periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas

production through various financial transactions which hedge the future prices received. These transactions include
financial price swaps whereby Devon will receive a fixed price for its production and pay a variable market price to the
contract counterparty, and costless price collars that set a floor and ceiling price for the hedged production. If the
applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, Devon
and the counterparty to the collars will settle the difference. These financial hedging activities are intended to support oil,
natural gas and NGLs 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.

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 57

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

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

BBLS/DAY

18,000
8,000
6,000
5,000
13,000
5,000
3,000

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

BBLS/DAY

2003

WEIGHTED AVERAGE
FLOOR
PRICE PER
BBL

CEILING
PRICE PER
BBL

$ 21.65
$ 23.38
$ 23.50
$ 20.40
$ 22.29
$ 23.30
$ 23.50

$ 27.91
$ 29.12
$ 29.31
$ 27.37
$ 27.52
$ 28.79
$ 29.18

2004

WEIGHTED AVERAGE
FLOOR
PRICE PER
BBL

CEILING
PRICE PER
BBL

MONTHS OF
PRODUCTION

Jan – Dec
Jan – Dec
Jul – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Jul – Dec

MONTHS OF
PRODUCTION

United States ($20.00 - $20.00/$26.50 - $28.00)
Canada ($20.00 - $20.00/$26.50 - $27.00)

2,000
2,000

$ 20.00
$ 20.00

$ 27.25
$ 26.75

Jan – Dec
Jan – Dec

GAS PRODUCTION

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

MMBTU/DAY

40,000
55,000
70,000
130,000
110,000
5,000
20,000
80,000
90,000
30,000
40,000

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

MMBTU/DAY

2003

WEIGHTED AVERAGE
FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

$
$
$
$
$
$
$
$
$
$
$

3.28
3.28
3.27
3.12
3.35
3.44
3.34
3.49
3.48
3.66
3.54

$
$
$
$
$
$
$
$
$
$
$

6.38
5.74
4.80
4.11
4.37
6.69
6.99
6.52
4.34
7.44
5.60

2004

WEIGHTED AVERAGE
FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

United States ($3.28 - $3.28/$5.74 - $5.81)
United States ($3.28 - $3.28/$6.48 - $6.48)
Canada ($3.65 - $3.65/$5.67 - $5.80)
Canada ($3.52 - $3.62/$6.55 - $6.70)
Canada ($3.53 - $3.56/$6.05 - $6.30)
Canada ($3.47 - $3.56/$7.42 - $7.70)

30,000
10,000
20,000
20,000
20,000
30,000

$
$
$
$
$
$

3.28
3.28
3.65
3.57
3.55
3.50

$
$
$
$
$
$

5.79
6.48
5.73
6.62
6.18
7.59

MONTHS OF
PRODUCTION

Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Apr – Sep
Jan – Dec
Jan – Dec
Jan – Dec
Apr – Oct
Jan – Dec

MONTHS OF
PRODUCTION

Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec
Jan – Dec

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 58

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.

We have 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 our various floating rate debt facilities (revolving credit facilities, commercial paper and term loan credit

facility) allow interest rates to be fixed at our 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 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.

We 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, our 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 10 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 59

MANAGEMENT’S RESPONSIBILITY
FOR FINANCIAL STAT E M E N T S

INDEPENDENT AUDITORS’ REPORT

Devon Energy Corporation’s management takes

responsibility for the accompanying consolidated financial
statements which have been prepared in conformity with
accounting principles generally accepted in the United
States of America. They are based on our best estimate
and judgment. Financial information elsewhere in this
annual report is consistent with the data presented in these
statements.

In order to carry out our responsibility concerning the

integrity and objectivity of published financial data, we
maintain an accounting system and related internal
controls. We believe the system is sufficient in all material
respects to provide reasonable assurance that financial
records are reliable for preparing financial statements and
that assets are safeguarded from loss or unauthorized use.
Our independent accounting firm, KPMG LLP,

provides objective consideration of Devon Energy
management’s discharge of its responsibilities as it relates
to the fairness of reported operating results and the
financial position of the company. This firm obtains and
maintains an understanding of our accounting and financial
controls to the extent necessary to audit our financial
statements, and employs all testing and verification
procedures it considers necessary to arrive at an opinion
on the fairness of financial statements.

The board of directors pursues its responsibilities for

the accompanying consolidated financial statements
through its Audit Committee. The Committee meets
periodically with management and the independent
auditors to assure that they are carrying out their
responsibilities. The independent auditors have full and free
access to the Committee members and meet with them to
discuss auditing and financial reporting matters.

DEVON ENERGY CORPORATION EXECUTIVE COMMITTEE

J. Larry Nichols
Chairman, President & CEO

Brian J. Jennings
Senior Vice President

J. Michael Lacey
Senior Vice President

Duke R. Ligon
Senior Vice President

Marian J. Moon
Senior Vice President

John Richels
Senior Vice President

Darryl G. Smette
Senior Vice President

William T. Vaughn
Senior Vice President

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.

Oklahoma City, Oklahoma
February 4, 2003

8626pg029_100_04-11 6/21/04 12:26 PM Page 60

C O N S O L I D ATED BALANCE SHEETS

DEVON ENERGY CORPORATION AND SUBSIDIARIES

DECEMBER 31, (IN MILLIONS, EXCEPT SHARE DATA)

2002

2001

2000

Assets
Current assets:

Cash and cash equivalents
Accounts receivable
Inventories
Deferred income taxes
Fair value of financial instruments
Income taxes receivable
Assets of discontinued operations
Investments and other current assets

Total current assets

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)

Less accumulated depreciation, depletion and amortization

Investment in ChevronTexaco Corporation common stock, at fair value
Fair value of financial instruments
Goodwill
Assets of discontinued operations
Other assets

Total assets

Liabilities and Stockholders’ Equity
Current liabilities:

Accounts payable:

Trade
Revenues and royalties due to others

Income taxes payable
Accrued interest payable
Merger related expenses payable
Fair value of financial instruments
Liabilities of discontinued operations
Deferred income taxes
Accrued expenses

Total current liabilities

Other liabilities
Debentures exchangeable into shares of ChevronTexaco Corporation

common stock
Other long-term debt
Deferred revenue
Fair value of financial instruments
Liabilities of discontinued operations
Deferred income taxes

Stockholders’ equity:

292
639
26
--
4
56
7
40
1,064

18,786
7,934
10,852
472
1
3,555
--
281
16,225

376
261
9
119
12
151
--
--
114
1,042
323

662
6,900
--
18
--
2,627

183
489
20
--
195
68
354
45
1,354

14,899
6,137
8,762
636
31
2,206
--
195
13,184

470
124
16
102
7
15
56
57
72
919
172

649
5,940
51
45
--
2,149

194
562
23
9
--
--
--
40
828

9,091
4,429
4,662
599
--
289
361
121
6,860

273
115
64
23
52
--
--
--
50
577
158

760
1,289
114
--
51
634

Preferred stock of $1 par value ($100 liquidation value) Authorized
4,500,000 shares; issued 1,500,000 in 2002, 2001 and 2000

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

Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Unamortized restricted stock awards
Treasury stock, at cost: 3,704,000 shares in 2002 and 3,754,000 shares in 2001

Total stockholders’ equity

Commitments and contingencies (Notes 11 and 12)

Total liabilities and stockholders' equity

See accompanying notes to consolidated financial statements

16
5,178
(84)
(267)
(3)
(188)
4,653

13
3,610
(147)
(28)
--
(190)
3,259

13
3,564
(215)
(85)
(1)
--
3,277

16,225

13,184

6,860

8626pg029_100_04-11 6/21/04 12:26 PM Page 61

C O N S O L I D ATED STATEMENTS OF OPERAT I O N S

DEVON ENERGY CORPORATION AND SUBSIDIARIES

YEAR ENDED DECEMBER 31, (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

2002

2001

2000

Revenues
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues

Operating Costs and Expenses
Lease operating expenses
Transportation costs
Production taxes
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization of property and equipment
Amortization of goodwill
General and administrative expenses
Expenses related to mergers
Reduction of carrying value of oil and gas properties

Total operating costs and expenses

Earnings from operations

Other Income (Expenses)

Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Impairment of ChevronTexaco Corporation common stock
Other income

Net other expenses

Earnings (loss) from continuing operations before income taxes and cumulative

effect of change in accounting principle

Income Tax Expense (Benefit)

Current
Deferred

Total income tax expense (benefit)

Earnings from continuing operations before cumulative effect of change in

accounting principle

Discontinued Operations

Results of discontinued operations before income taxes (including net gain on

disposal of $31 million in 2002)

Income tax expense

Net results of discontinued operations

Earnings before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle
Net earnings
Preferred stock dividends
Net earnings applicable to common shareholders

Basic net earnings per share:

Earnings from continuing operations
Net results of discontinued operations
Cumulative effect of change in accounting principle
Net earnings

Diluted net earnings per share:

Earnings from continuing operations
Net results of discontinued operations
Cumulative effect of change in accounting principle
Net earnings

Weighted average common shares outstanding:

Basic
Diluted

See accompanying notes to consolidated financial statements

909
2,133
275
999
4,316

621
154
111
808
1,211
--
219
--
651
3,775

541

(533)
1
28
(205)
34
(675)

(134)

23
(216)
(193)

54
9
45

104
--
104
10
94

0.32
0.29
--
0.61

155
156

784
1,878
131
71
2,864

467
83
116
47
831
34
114
1
979
2,672

192

(220)
(11)
(2)
--
69
(164)

906
1,474
154
53
2,587

388
53
103
28
662
41
96
60
--
1,431

1,156

(155)
(3)
--
--
40
(118)

1,038

48
(43)
5

120
257
377

661

56
25
31

54
49
103
10
93

0.09
0.25
0.39
0.73

0.09
0.25
0.38
0.72

128
130

104
35
69

730
--
730
10
720

5.13
0.53
--
5.66

4.97
0.53
--
5.50

127
132

8626pg029_100_04-11 6/21/04 12:26 PM Page 62

C O N S O L I D ATED STATEMENTS OF STOCKHOLDERS’ EQUITY

DEVON ENERGY CORPORATION AND SUBSIDIARIES

(IN MILLIONS)

Balance as of December 31, 1999

Comprehensive earnings:

Net earnings
Other comprehensive earnings (loss), net of tax:

Foreign currency translation adjustments
Minimum pension liability adjustment
Unrealized loss on marketable securities
Other comprehensive loss

Comprehensive earnings

Stock issued
Stock repurchased
Tax benefit related to employee stock options
Dividends on common stock
Dividends on preferred stock
Grant of restricted stock awards
Amortization of restricted stock awards

Balance as of December 31, 2000

Comprehensive earnings:

Net earnings
Other comprehensive earnings (loss), net of tax:

Foreign currency translation adjustments
Cumulative effect of change in accounting

principle

Reclassification adjustment for derivative gains

reclassified into oil and gas sales

Change in fair value of financial instruments
Minimum pension liability adjustment
Unrealized gain on marketable securities

Other comprehensive earnings

Comprehensive earnings

Stock issued
Stock repurchased
Tax benefit related to employee stock options
Dividends on common stock
Dividends on preferred stock
Amortization of restricted stock awards

Balance as of December 31, 2001

Comprehensive loss:

Net earnings
Other comprehensive earnings (loss), net of tax:

Foreign currency translation adjustments
Reclassification adjustment for derivative gains

reclassified into oil and gas sales

Change in fair value of financial instruments
Minimum pension liability adjustment
Unrealized loss on marketable securities
Impairment of marketable securities

Other comprehensive loss

Comprehensive loss

Stock issued
Tax benefit related to employee stock options
Dividends on common stock
Dividends on preferred stock
Grant of restricted stock awards

Balance as of December 31, 2002

See accompanying notes to consolidated financial statements

PREFERRED COMMON PAID-IN
STOCK CAPITAL

STOCK

ADDITIONAL

ACCUMULATED
OTHER
COMPRE-
ACCUMULATED HENSIVE

DEFICIT

LOSS

UNAMORTIZED
RESTRICTED
STOCK
AWARDS

--
--
--

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

--
--
--
--

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

--
--
--
--
--

3,492

(909)

(65)

--
--
--

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

--
--
--

69
--
3
--
--
--
--

730

--
--
--

(4)
--
--
(22)
(10)
--
--

(10)
1
(11)

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

3,564

(215)

(85)

--
--
--
--

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

--
--
--
--

48
(14)
12
--
--
--

103

--
--
--
--

--
--
--
(25)
(10)
--

(107)

(37)

(20)
216
(17)
22

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

3,610

(147)

(28)

--
--
--
--
--

3
--
--
--
--

--
--
--
--
--

1,562
6
--
--
--

5,178

104

--
--
--
--
--

--
--
(31)
(10)
--

(84)

(39)
(217)
(54)
(103)
128

--
--
--
--
--

(267)

--
--
--

--
--
--
--
--
(5)
4

(1)

--
--
--
--

--
--
--
--
--
1

--
--
--
--
--

--
--
--
--
(3)

(3)

TOTAL
STOCK-

TREASURY HOLDERS’

STOCK

EQUITY

(11)

2,521

--
--
--

21
(10)
--
--
--
--
--

--
--
--
--

--
(190)
--
--
--
--

730

(10)
1
(11)
(20)

710

86
(10)
3
(22)
(10)
(5)
4

3,277

103

(107)

(37)

(20)
216
(17)
22
57

160

48
(204)
12
(25)
(10)
1

(190)

3,259

--
--
--
--
--

2
--
--
--
--

104

(39)
(217)
(54)
(103)
128
(239)

(135)

1,567
6
(31)
(10)
(3)

(188)

4,653

8626pg029_100_04-11 6/21/04 12:26 PM Page 63

C O N S O L I D ATED STATEMENTS OF CASH FLOWS

DEVON ENERGY CORPORATION AND SUBSIDIARIES

YEAR ENDED DECEMBER 31, (IN MILLIONS)

2002

2001

2000

Cash Flows From Operating Activities
Earnings from continuing operations
Adjustments to reconcile earnings from continuing operations to net

cash provided by operating activities:

Depreciation, depletion and amortization of property and equipment
Amortization of goodwill
Accretion of discounts on long-term debt, net
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Reduction of carrying value of oil and gas properties
Impairment of ChevronTexaco Corporation common stock
Operating cash flows from discontinued operations
Loss (gain) on sale of assets
Deferred income tax expense (benefit)
Other
Changes in assets and liabilities, net of effects of acquisitions of

businesses:

(Increase) decrease in:
Accounts receivable
Inventories
Income taxes receivable
Investments and other current assets

(Decrease) increase in:
Accounts payable
Income taxes payable
Accrued interest and expenses
Deferred revenue
Long-term other liabilities

Net cash provided by operating activities

Cash Flows From Investing Activities

Proceeds from sale of property and equipment
Proceeds from sale of investments
Capital expenditures, including acquisitions of businesses
Discontinued operations (including net proceeds from sale of $336 million

in 2002)

Increase in other assets

Net cash used in investing activities

Cash Flows From Financing Activities

Proceeds from borrowings of long-term debt, net of issuance costs
Principal payments on long-term debt
Issuance of common stock, net of issuance costs
Repurchase of common stock
Issuance of treasury stock
Dividends paid on common stock
Dividends paid on preferred stock
Decrease in long-term other liabilities

Net cash provided by (used in) financing activities

Effect of exchange rate changes on cash
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

See accompanying notes to consolidated financial statements

661

1,211
--
33
(1)
(28)
651
205
28
(2)
(216)
(9)

(80)
10
--
12

(74)
21
36
(46)
(56)
1,754

1,067
--
(3,426)

316
(3)
(2,046)

6,067
(5,657)
32
--
--
(31)
(10)
--
401
--
109
183
292

831
34
26
11
2
979
--
134
2
(43)
(3)

203
12
(68)
(8)

37
(129)
(46)
(63)
(24)
1,910

41
--
(5,235)

(91)
--
(5,285)

6,199
(2,638)
48
(204)
--
(25)
(10)
--
3,370
(6)
(11)
194
183

662
41
3
3
--
--
--
110
(1)
257
4

(272)
(5)
--
3

78
61
2
8
(26)
1,589

101
13
(1,148)

(132)
(7)
(1,173)

2,580
(2,952)
51
(10)
25
(22)
(10)
(52)
(390)
(1)
25
169
194

8626pg029_100_04-11 6/21/04 12:26 PM Page 64

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 geographical 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 portion 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

o ff s h o re 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 unit that 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. Such estimates and assumptions 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 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.

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-
p roduction 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 re l a t i o n s h i p
between capitalized costs and proved reserves. All costs related to production activities, including workover costs incurre d
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

8626pg029_100_04-11 6/21/04 12:26 PM Page 65

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 the 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.

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.

E ffective January 1, 2002, Devon adopted the remaining provisions of Statement of Financial Accounting Standards No.
142, Goodwill and Other Intangible Assets ( S FAS 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.

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.

Net earnings applicable to common shareholders, as reported
Add back amortization of goodwill
Net earnings applicable to common shareholders, as adjusted

Basic earnings per share:

Net earnings applicable to common shareholders, as reported
Amortization of goodwill
Net earnings applicable to common shareholders, as adjusted

Diluted earnings per share:

Net earnings applicable to common shareholders, as reported
Amortization of goodwill
Net earnings applicable to common shareholders, as adjusted

FOR THE YEAR ENDED DECEMBER 31,
2002
2001
(IN MILLIONS, EXCEPT PER SHARE DATA)

2000

94
-
94

0.61
--
0.61

93
34
127

0.73
0.26
0.99

0.72
0.26
0.98

720
41
761

5.66
0.32
5.98

5.50
0.31
5.81

8626pg029_100_04-11 6/21/04 12:26 PM Page 66

Revenue Recognition and Gas Balancing

Oil and gas revenues are recognized when sold. During the course of normal operations, Devon and other joint intere s t

owners of natural gas reservoirs will take more or less than their respective ownership share of the natural gas volumes
p roduced. 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 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. 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

i n t e rest 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.

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. These losses reflect 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

8626pg029_100_04-11 6/21/04 12:26 PM Page 67

of oil and gas that 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. The following
table illustrates those differences.

Net earnings available to
common shareholders:

As reported
Pro forma

Net earnings per share available to

common shareholders:

As reported:
Basic
Diluted
Pro forma:
Basic
Diluted

Major Purchasers

YEAR ENDED DECEMBER 31,
2000
2001
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

2002

$
$

94
78

0.61
0.61

0.51
0.50

93
79

720
702

0.73
0.72

0.62
0.61

5.66
5.50

5.51
5.36

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 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. Under that method, deferred tax assets and
liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying
amounts of assets and liabilities and their respective tax bases. The future tax consequences attributable to the future
utilization of existing tax net operating loss and other types of carryforwards are also recognized. 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. It supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of. It also supersedes 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).

8626pg029_100_04-11 6/21/04 12:26 PM Page 68

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.

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:

Major Classes of Assets and Liabilities
Cash
Accounts receivable
Inventories
Other current assets
Property and equipment, net of accumulated
depreciation, depletion and amortization

Other assets

Total assets

Accounts payable – trade
Income taxes payable
Accrued expense
Other liabilities
Deferred income taxes
Total liabilities

Revenues
Oil sales
Gas sales
NGL sales

Total revenues

2002

AS OF DECEMBER 31,
2001
(IN MILLIONS)

--
7
--
--

--
--
7

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

10
48
21
2

266
7
354

41
14
1
7
(7)
56

2000

34
36
24
12

248
7
361

49
2
1
6
(7)
51

FOR THE YEAR ENDED DECEMBER 31,
2001
2002
(IN MILLIONS)

2000

72
7
1
80

174
12
1
187

173
11
--
184

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 69

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.

Year Ended December 31, 2002:

Basic earnings per shar e

Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options

Diluted earnings per shar e

Year Ended December 31, 2001:

Basic earnings per shar e

Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options

Diluted earnings per shar e

Year Ended December 31, 2000:

Basic earnings per share

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)

Potential common shares issuable upon the exercise

of outstanding stock options

NET
EARNINGS
PER SHARE

$ 0.61

$ 0.73

$ 0.72

$ 5.66

NET EARNINGS
APPLICABLE
TO COMMON
STOCKHOLDERS

WEIGHTED
AVERAGE
COMMON SHARES
OUTSTANDING

(IN MILLIONS)

720

155

156

128

130

127

Diluted earnings per share

725

132

$ 5.50

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.

Options excluded from dilution calculation

(in millions)

Range of exercise prices
Weighted average exercise price

2002

2001

2000

5
$45.49 - $89.66
$50.85

3
$48.13 - $89.66
$56.11

1
$55.54 - $89.66
$66.64

The excluded options for 2002 expire between January 24, 2003 and December 2, 2012.

8626pg029_100_04-11 6/21/04 12:26 PM Page 70

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 December 31, 2002, 2001 and
2000, and changes during each of the years then ended, is presented in the following table.

FOREIGN
CURRENCY
TRANSLATION
ADJUSTMENTS

CHANGE IN
FAIR VALUE OF
FINANCIAL
INSTRUMENTS

MINIMUM
PENSION
LIABILITY
ADJUSTMENTS

UNREALIZED
GAIN (LOSS) ON
MARKETABLE
SECURITIES

TOTAL

(IN MILLIONS)

Balance as of December 31, 1999

2000 activity
Deferred taxes
2000 activity, net of deferred taxes

Balance as of December 31, 2000

2001 activity
Deferred taxes
2001 activity, net of deferred taxes

Balance as of December 31, 2001

2002 activity
Deferred taxes
2002 activity, net of deferred taxes

(28)
(10)
--
(10)

(38)
(107)
--
(107)

(145)
46
--
46

Balance as of December 31, 2002

(99)

--
--
--
--

--
243
(84)
159

159
(379)
123
(256)

(97)

(1)
1
--
1

--
(28)
11
(17)

(17)
(85)
31
(54)

(71)

(36)
(18)
7
(11)

(47)
36
(14)
22

(25)
41
(16)
25

(65)
(27)
7
(20)

(85)
144
(87)
57

(28)
(377)
138
(239)

(267)

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 Chevro n Texaco 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.

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 71

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.

The FASB issued Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities, in June 2002.

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 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.

Reclassification

Certain of the 2001 and 2000 amounts in the accompanying consolidated financial statements have been reclassified

to conform to the 2002 presentation.

8626pg029_100_04-11 6/21/04 12:26 PM Page 72

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.

(IN MILLIONS, EXCEPT SHARE PRICE)

Calculation and allocation of purchase price:

Shares of Devon common stock issued to Mitchell

stockholders

Average Devon stock price
Fair value of common stock issued
Cash paid to Mitchell stockholders, calculated at $31 per

outstanding common share of Mitchell

Fair value of Devon common stock and cash to be issued to

Mitchell stockholders

Plus estimated acquisition costs incurred
Plus fair value of Mitchell employee stock options assumed

by Devon

Total purchase price

Plus fair value of liabilities assumed by Devon:

Current liabilities
Long-term debt
Other long-term liabilities
Deferred income taxes

Total purchase price plus liabilities assumed

Fair value of assets acquired by Devon:

Current assets
Proved oil and gas properties
Unproved oil and gas properties
Marketing and midstream facilities and equipment
Other property and equipment
Other assets
Goodwill (none deductible for income taxes)

Total fair value of assets acquired

Anderson Exploration Ltd. Acquisition

$
$

30
50.95
1,512

1,573

3,085
84

27
3,196

190
506
128
796
4,816

169
1,535
639
1,000
15
103
1,355

4,816

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 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 73

The calculation of the purchase price and the allocation to assets and liabilities as of October 15, 2001, are shown below.

(IN MILLIONS, EXCEPT SHARE PRICE)

Calculation and allocation of purchase price:

Number of Anderson common shares outstanding
Acquisition price per share
Cash paid to Anderson stockholders
Cash paid to settle Anderson employees’ stock options and

appreciation rights

Plus estimated acquisition costs incurred

Total purchase price

Plus fair value of liabilities assumed by Devon:

Current liabilities
Long-term debt
Other long-term liabilities
Fair value of financial instruments
Deferred income taxes

Total purchase price plus liabilities assumed

Fair value of assets acquired by Devon:

Current assets
Proved oil and gas properties
Unproved oil and gas properties
Other property and equipment
Goodwill (none deductible for income tax purposes)

Total fair value of assets acquired

$
$

132
25.68
3,386

92
3,478
35
3,513

251
1,017
3
30
1,407
6,221

214
2,605
1,432
21
1,949
6,221

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 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 74

PRO FORMA INFORMATION YEAR
ENDED DECEMBER 31,

2002

2001

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS
AND PRODUCTION VOLUMES)
(UNAUDITED)

Revenues
Oil sales
Gas sales
Natural gas liquids sales
Marketing and midstream revenues

Total revenues

Total operating costs and expenses

Earnings from operations

Other Income (Expenses)

Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Impairment of ChevronTexaco Corporation common stock
Other income

Net other expenses

Earnings (loss) from continuing operations before income tax expense (benefit)

and cumulative effect of change in accounting principle

Income Tax Expense (Benefit)

Current
Deferred

Total income tax expense (benefit)

Earnings from continuing operations before cumulative effect of change in

accounting principle

Discontinued Operations

Results of discontinued operations before income taxes (including net gain on

disposal of $31 million in 2002)

Total income tax expense

Net results of discontinued operations

911
2,155
280
1,069
4,415

625
157
112
873
1,230
--
224
--
651
3,872

543

(534)
1
28
(205)
34
(676)

(133)

23
(215)
(192)

54
9
45

104
--
104
10
94

1,059
3,133
306
1,238
5,736

705
155
148
1,085
1,358
34
205
1
1,136
4,827

909

(507)
(19)
(15)
--
68
(473)

436

55
96
151

285

56
25
31

316
49
365
10
355

8626pg029_100_04-11 6/21/04 12:26 PM Page 75

Basic earnings per average common share outstanding:

Earnings from continuing operations
Net results of discontinued operations
Cumulative effect of change in accounting principle
Net earnings

Diluted earnings per average common share outstanding:

Earnings from continuing operations
Net results of discontinued operations
Cumulative effect of change in accounting principle
Net earnings

Weighted average common shares outstanding - basic
Weighted average common shares outstanding - diluted

Production volumes:

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
MMBoe

Santa Fe Snyder Merger

PRO FORMA INFORMATION YEAR
ENDED DECEMBER 31,

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS
AND PRODUCTION VOLUMES)

2002

0.31
0.29
--
0.60

157
158

42
771
20
191

2001

1.75
0.21
0.31
2.27

1.73
0.20
0.30
2.23

157
164

50
802
17
201

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:

2002

YEAR ENDED DECEMBER 31,
2001
(IN MILLIONS)

2000

Interest paid
Income taxes paid (refunded)

$
$

248
(12)

118
185

155
80

The 2002 Mitchell acquisition and the 2001 Anderson acquisition involved non-cash consideration as presented below:

Value of common stock issued
Employee stock options assumed
Liabilities assumed
Deferred tax liability created

Fair value of assets acquired with non-cash consideration

2002

2001

(IN MILLIONS)

1,512
27
824
796

3,159

--
--
1,301
1,407

2,708

8626pg029_100_04-11 6/21/04 12:26 PM Page 76

4. Accounts Receivable

The components of accounts receivable included the following:

Oil, gas and natural gas liquids revenue accruals
Joint interest billings
Marketing and midstream revenues
Other

Allowance for doubtful accounts
Net accounts receivable

5. Property And Equipment

Property and equipment included the following:

Oil and gas properties:

Subject to amortization
Not subject to amortization:

Acquired in 2002
Acquired in 2001
Acquired in 2000
Acquired prior to 2000

Accumulated depreciation, depletion

and amortization

Net oil and gas properties

Other property and equipment
Accumulated depreciation and amortization

Net other property and equipment

Property and equipment, net of accumulated
depreciation, depletion and amortization

2002

422
102
73
52
649
(10)
639

DECEMBER 31,
2001
(IN MILLIONS)

275
145
1
72
493
(4)
489

2000

402
123
--
41
566
(4)
562

2002

DECEMBER 31,
2001
(IN MILLIONS)

2000

15,020

12,580

8,555

730
1,338
52
169

--
1,638
65
226

--
--
74
240

(7,796)

(6,048)

(4,382)

9,513

8,461

4,487

1,477
(138)

1,339

390
(89)

301

222
(47)

175

10,852

8,762

4,662

The costs not subject to amortization relate to unproved properties that 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:

2002

YEAR ENDED DECEMBER 31,
2001
(IN MILLIONS)

2000

Depreciation, depletion and amortization

of oil and gas properties

Depreciation and amortization of other

property and equipment
Amortization of other assets

Total

1,106

97
8

1,211

793

30
8

831

632

23
7

662

8626pg029_100_04-11 6/21/04 12:26 PM Page 77

6. Long-Term Debt and Related Expenses

A summary of Devon’s long-term debt is as follows:

Borrowings under credit facilities with banks
Commercial paper borrowings
$3 billion term loan credit facility
Debentures exchangeable into shares of

ChevronTexaco Corporation common stock:
4.90% due August 15, 2008
4.95% due August 15, 2008
Discount on exchangeable debentures
Zero coupon convertible senior debentures

exchangeable into shares of Devon Energy Corp.
common stock, 3.875% due June 27, 2020

Other debentures and notes:

6.75% due February 15, 2004
8.05% due June 15, 2004
7.25% due July 18, 2005
7.42% due October 1, 2005
7.57% due October 4, 2005
10.25% due November 1, 2005
6.55% due August 2, 2006
8.75% due June 15, 2007
10.125% due November 15, 2009
6.75% due March 15, 2011
6.875% due September 30, 2011
7.875% due September 30, 2031
7.95% due April 15, 2032
Fair value adjustment on 8.05% notes

related to interest rate swap

Net (discount) premium on other debentures

and notes

Less amount classified as current

Long-term debt

2002

DECEMBER 31,
2001
(IN MILLIONS)

2000

--
--
1,135

444
316
(98)

388

211
125
111
--
--
236
127
--
177
400
1,750
1,250
1,000

(15)
7,562
--

50
75
1,046

444
316
(111)

374

--
125
110
23
31
236
126
175
177
400
1,750
1,250
--

(8)
6,589
--

7,562

6,589

147
--
--

444
316
--

360

--
125
--
--
--
250
--
175
200
--
--
--
--

32
2,049
--

2,049

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):

2003
2004
2005
2006
2007
2008 and thereafter
Total

--
336
347
1,262
--
5,725
7,670

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 78

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

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.

Letter of Credit Facility

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.

The terms of this facility require repayment of the debt during the following periods:

April 15, 2006
October 15, 2006

Total

(IN MILLIONS)

335
800
1,135

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 79

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% 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 merg e r. The fair values of the exchangeable

d e b e n t u res 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 re c o rded on these exchangeable debenture s .
H o w e v e r, 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 Chevro n Texaco common stock that is embedded in the debentures. Accord i n g l y, the debt portion of the
d e b e n t u res was reduced by $140 million as of August 17, 1999. This discount is being accreted using the effective intere s t
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 $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 re c o rded 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 30 nor more than 60 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
a re being amortized or accreted using the effective interest method. All of the notes are general unsecured obligations of Devon.

FAIR VALUE OF
DEBT ASSUMED

EFFECTIVE RATE OF
DEBT ASSUMED
(IN MILLIONS)

DEBT ASSUMED

7.25% senior notes due 2005
7.42% senior notes due 2005
7.57% senior notes due 2005
6.55% senior notes due 2006
6.75% senior notes due 2011

$ 116
24
33
129
400

6.3%
5.7%
5.7%
6.5%
6.8%

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 merg e r. The fair values of the re s p e c t i v e

d e b e n t u res were determined using August 17, 1999, market interest rates. As a result, premiums were re c o rded on these
d e b e n t u res 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, re s p e c t i v e l y. 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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 80

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%.

Interest on the debt securities is payable by Devon Financing semi-annually 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. This is 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

Interest Expense

Following are the components of interest expense for the years 2002, 2001 and 2000:

2002

YEAR ENDED DECEMBER 31,
2001
(IN MILLIONS)

2000

Interest based on debt outstanding
Accretion (amortization) of debt discount

(premium), net

Facility and agency fees
Amortization of capitalized loan costs
Capitalized interest
Early retirement premiums
Other

499

200

157

13
2
8
(4)
8
7

10
1
3
(3)
7
2

(4)
3
2
(3)
--
--

Total interest expense

533

220

155

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.

7. Income Taxes

At December 31, 2002, Devon had the following carryforwards available to reduce future income taxes:

TYPES OF CARRYFORWARD

Net operating loss – U.S. federal
Net operating loss – various states
Net operating loss – Canada
Net operating loss – International
Minimum tax credits

YEARS OF
EXPIRATION
(IN MILLIONS)

2008 – 2021
2003 – 2016
2005 – 2009
Indefinite
Indefinite

CARRYFORWARD
AMOUNTS

$
$
$
$
$

10
119
119
63
164

8626pg029_100_04-11 6/21/04 12:26 PM Page 81

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:

2002

YEAR ENDED DECEMBER 31,
2001
(IN MILLIONS)

2000

Earnings (loss) from continuing operations before income taxes:

U.S
Canada
International

Total

Current income tax expense (benefit):

U.S. federal
Various states
Canada
International

Total current tax expense
Deferred income tax expense (benefit):

U.S. federal
Various states
Canada
International

Total deferred tax expense (benefit)

Total income tax expense (benefit)

354
(515)
27
(134)

(34)
11
28
18
23

56
(14)
(253)
(5)
(216)
(193)

458
(357)
(73)
28

23
6
8
11
48

124
(32)
(145)
10
(43)
5

872
156
10
1,038

107
6
2
5
120

152
33
67
5
257
377

The taxes on the results of discontinued operations presented in the accompanying statements of operations were all

related to foreign operations.

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:

2002

YEAR ENDED DECEMBER 31,
2001
(IN MILLIONS)

2000

Expected income tax (benefit) based
on U.S. statutory tax rate of 35%

Benefit from disposition of certain

foreign assets

Financial expenses not deductible for

income tax purposes
Dividends received deduction
Nonconventional fuel source credits
State income taxes
Taxation on foreign operations
Other
Total income tax expense (benefit)

(47)

--
(5)
(19)
7
(121)
(8)
(193)

12
(5)
(19)
4
5
(2)
5

363

(46)

15
(5)
(8)
15
22
21
377

8626pg029_100_04-11 6/21/04 12:26 PM Page 82

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:

Deferred tax assets:

Net operating loss carryforwards
Minimum tax credit carryforwards
Long-term debt
Fair value of financial instruments
Pension benefit obligation
Other
Total deferred tax assets

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

ChevronTexaco Corporation common stock
Other
Total deferred tax liabilities

Net deferred tax liability

2002

78
164
--
46
42
53
383

DECEMBER 31,
2001
(IN MILLIONS)

39
118
6
7
11
26
207

(2,863)
(147)
--
(3,010)

(2,189)
(213)
(11)
(2,413)

(2,627)

(2,206)

2000

123
85
17
--
--
95
320

(694)
(167)
(84)
(945)

(625)

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
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

8626pg029_100_04-11 6/21/04 12:26 PM Page 83

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 “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.

OPTIONS OUTSTANDING

OPTIONS EXERCISABLE

Balance at December 31, 1999

Options granted
Options exercised
Options forfeited

Balance at December 31, 2000

Options granted
Options exercised
Options forfeited

Balance at December 31, 2001

Options granted
Options assumed in the Mitchell

acquisition
Options exercised
Options forfeited

NUMBER
OUTSTANDING

(IN THOUSANDS)

8,554
1,625
(2,489)
(334)

7,356
2,601
(1,505)
(268)

8,184
2,807

1,554
(899)
(415)

WEIGHTED
AVERAGE
EXERCISE
PRICE

$ 38.20
$ 51.43
$ 33.11
$ 60.35

$ 41.84
$ 35.43
$ 31.13
$ 62.77

$ 41.09
$ 45.77

$ 26.82
$ 29.33
$ 47.12

NUMBER
EXERCISABLE

(IN THOUSANDS)

WEIGHTED
AVERAGE
EXERCISE
PRICE

7,064

$ 39.55

6,025

$ 40.72

5,516

$ 41.93

Balance at December 31, 2002

11,231

$ 41.00

6,991

$ 40.05

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%.

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The following table summarizes information about Devon’s stock options that were outstanding, and those which were

exercisable, as of December 31, 2002:

RANGE OF
EXERCISE
PRICES

NUMBER
OUTSTANDING
(IN THOUSANDS)

OPTIONS OUTSTANDING
WEIGHTED
AVERAGE
REMAINING
LIFE

WEIGHTED
AVERAGE
EXERCISE
PRICE

$10.270-$25.667
$29.125-$33.381
$34.375-$39.773
$40.483-$49.950
$50.142-$59.813
$60.150-$89.660

1,157
956
3,281
3,566
1,772
499
11,231

2.70 Years
6.12 Years
6.74 Years
6.99 Years
5.88 Years
4.36 Years
6.11 Years

$
$
$
$
$
$
$

18.63
30.87
35.40
46.00
53.04
70.79
41.00

OPTIONS EXERCISABLE

NUMBER
EXERCISABLE
(IN THOUSANDS)

1,157
956
1,735
1,244
1,404
495
6,991

WEIGHTED
AVERAGE
EXERCISE
PRICE

$
$
$
$
$
$
$

18.63
30.87
35.72
45.82
53.36
70.87
40.05

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 10 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 $0.01 per

right until the rights become exercisable.

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.

2002

CARRYING
AMOUNT

$
Investments
$
Oil and gas price hedge agreements
$
Interest rate swap agreements
$
Electricity hedge agreements
Foreign exchange hedge agreements
$
Embedded option in exchangeable debenture s $
Long-term debt

479
(144)
(5)
(2)
(1)
(12)
$ (7,562)

FAIR
VALUE

479
(144)
(5)
(2)
(1)
(12)
(8,425)

2001

2000

CARRYING
AMOUNT

FAIR
VALUE

CARRYING
AMOUNT

(IN MILLIONS)

644
225
(9)
(12)
(4)
(34)
(6,589)

644
225
(9)
(12)
(4)
(34)
(6,699)

606
--
--
--
--
--
(2,049)

FAIR
VALUE

606
(58)
--
--
(1)
--
(2,050)

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.

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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

T h rough 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
n e c e s s a r y, the prices related to these swaps have been adjusted for certain transportation costs that are netted against the price
re c o rded 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

OIL PRODUCTION

YEAR
2003
2004

BBLS/DAY
53,537
4,000

WEIGHTED AVERAGE
FLOOR PRICE CEILING PRICE

PER
BBL
$ 22.26
$ 20.00

PER
BBL
$ 28.14
$ 27.00

GAS PRODUCTION

YEAR

MMBTU/DAY

WEIGHTED AVERAGE
FLOOR PRICE CEILING PRICE

PER
MMBTU

2003
2004

655,096
130,000

$
$

3.34
3.47

$
$

5.11
6.44

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 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.

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.

8626pg029_100_04-11 6/21/04 12:26 PM Page 86

10. Retirement Plans

Devon has non-contributory defined benefit re t i rement plans (the “Basic Plans”) that include U.S. and Canadian employees

meeting certain age and service re q u i rements. The benefits are based on the employee’s years of service and compensation.
During 2002, Devon established a funding policy re g a rding 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 re q u i red during this period will depend on investment re t u rns 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.

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.

PENSION BENEFITS
2001

2000

2002