Devon Energy Annual Report 2003

FY2003 Annual Report · Devon Energy

Loading PDF…

OUR MISSION
Devon Energy is a results-oriented oil and gas
company that builds value for our shareholders
through our employees by creating an atmosphere
of optimism, teamwork, creativity, resourcefulness
and by dealing with everyone in an open and
ethical manner.

COMPANY PROFILE
Devon is engaged in oil and gas exploration,
production and property acquisitions. Devon is the
largest U.S.-based independent oil and gas
producer 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.

FORWARD-LOOKING STATEMENTS
This annual report includes “forward-looking state-
ments” as defined by the Securities and Exchange
Commission. Such statements are those
concerning Devon’s plans, expectations and objec-
tives for future operations including reserve poten-
tial and exploration target size. These statements
address future financial position, business strategy,
future capital expenditures, projected oil and gas
production and future costs. Devon believes that
the expectations reflected in such forward-looking
statements are reasonable. 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 “Manage-
ment’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 are available free of charge on the
company’s website, www.devonenergy.com, or will
be furnished upon request to the company.

Contents

8. Devon and its employees give back
to our communities.

2. LARRY NICHOLS reviews the year 2003
and shares Devon’s long-term strategy in
his letter to shareholders.

5. FIVE-YEAR HIGHLIGHTS AND COMPARISONS

WALL STREET’S QUESTIONS ARE ANSWERED by
members of Devon’s senior management.
Q&As can be found on pages 6,11,12,14,16, 19 and 20.

6. INNOVATION underpins Devon’s approach to
accessing oil and gas that was previously out of reach.

10. EXPLORATION AND PRODUCTION PORTFOLIO
Assets acquired from Ocean enhance our already
significant portfolio of oil and gas properties.

13. Liquids from gas.

14. STABILITY is a defining characteristic
of Devon. A balance of stable development
and focused exploration is enhanced
by our complementary midstream
operations.

18.

11-YEAR PROPERTY DATA

20. TECHNOLOGY
leads the way to
continuing success.

22. OPERATING STATISTICS BY AREA

23. CORPORATE GOVERNANCE OVERVIEW

17. Beneath the surface, horizontally.

24. KEY PROPERTY HIGHLIGHTS This fold-out describes key properties
and summarizes activity.

ANNUAL REPORT THEME
“Beneath the Surface” was one of nearly 900
entries from employees in Devon’s annual report
theme contest. The winning entry was submitted by
Doug Bridwell in Bridgeport, Texas.

29.

FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS

107. BIOGRAPHIES OF DIRECTORS AND SENIOR OFFICERS

110. GLOSSARY OF TERMS

111. COMMON STOCK TRADING DATA AND INVESTOR INFORMATION

B e n e a t h t h e S u r f a c e

A Look Beneath the Surface Reveals
Our Long-term Strategy

E A R F E L L O W S H A R E H O L D E R S :

The record results of 2003 reflect one of our most

By many measures, 2003 was

important accomplishments of the year—our merger with

the best year in Devon’s

Ocean Energy. Devon merged with Ocean on April 25, 2003,

history. We increased oil and

following overwhelming approval by the shareholders of both

gas production 21%, setting

companies. Former Ocean shareholders received 74 million

an all-time record. Higher

Devon common shares in exchange for their Ocean shares.

production and stronger prices

The Ocean merger enhanced our production profile.

drove 2003 revenues up 70%,

Ocean brought development projects at Nansen/Boomvang

to a record $7.4 billion.

Devon’s marketing and

and Zia in the deepwater Gulf of Mexico and the Southern

Expansion Area of Zafiro in Equatorial Guinea. Production

midstream operations also

from these projects supplemented Devon’s 2003 production

delivered their best results

growth from the Barnett Shale in north Texas and our Panyu

ever, contributing $286 million

project in the South China Sea. On a pro forma combined

to operating margins. Net

basis, Devon and Ocean increased 2003 production by 5.5%

earnings climbed to $1.7 billion

over 2002. We expect to deliver healthy production growth

or $8.07 per diluted share—the

again in 2004—without the benefit of acquisitions. The

highest levels in Devon’s history. We finished the year with

proved reserves of more than two billion equivalent barrels, yet

deepwater Gulf of Mexico development projects at Red Hawk

and Magnolia, described elsewhere in this annual report, are

scheduled to commence production in the second half of

another record.

We also had a very good year in

2003 from an operational perspective.

We drilled 1,884 successful development

wells and 232 exploratory discoveries.

One of those discoveries, St. Malo in the

Total Revenues
($ Billions)

Net Cash Provided
by Operating
Activities
($ Billions)

2004. Devon’s share of these projects is

expected to bring approximately 20

thousand equivalent barrels per day of

new production.

Beyond this immediate production

deepwater Gulf of Mexico, confirmed a

4
.
7

8
.
3

growth, the Ocean merger also

major new hydrocarbon trend. On the

development front, we increased

production from the Barnett Shale,

3
.
4

already the largest natural gas field in

Texas, by more than 20%. We launched

a multi-year, heavy oil project in Canada

with the potential to add 300 million

barrels of new oil reserves. Outside

North America, we added substantial

production volumes in West Africa and

China.

9
.
6 2
.
2

9
.
1

8
.
1

6
.
1

1
.
1

5
.
0

Strong oil and gas
prices and record
production drove 2003
revenues ahead 70% to
$7.4 billion...

...and allowed Devon to
more than double net
cash provided by
operating activities to
$3.8 billion.

brightened Devon’s longer-term outlook.

Ocean focused on offshore exploration.

Through the merger, Devon acquired

many talented oil and gas professionals

and fortified our exploration inventory.

The Ocean assets bolstered Devon’s

already extensive deepwater Gulf of

Mexico acreage position. We now hold

more than a million net acres in the

deepwater Gulf, the most of any

independent. Previous Ocean

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

(cid:1) LARRY NICHOLS
Chairman and CEO

deepwater discoveries at

Merganser and Vortex

await development and

should add reserves and

production in the future.

Ocean also brought a

large inventory of high-

potential exploratory

blocks offshore West

Africa. During 2004 we

will test several of these

promising international

prospects.

Building for the
Long Run

Including the 550

million-plus equivalent

barrels acquired in the

S
t
r
a
t
e
g
y
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

we invested about $500

million in 2003 on long

cycle-time projects.

Most of these projects

are designed to provide

growth beyond 2004.

While these development

projects and long-term

investments drive up our

near-term finding costs,

they position Devon to

benefit in the future.

Devon is now the largest

U.S.-based independent

oil and gas producer. Our

arrival to this position

coincides with one of the

strongest periods for oil

and gas prices in history.

Ocean merger, Devon replaced 321% of 2003 production. We

This is driving our earnings and cash flow and allowing us to

closed the year with 2.1 billion equivalent barrels of proved oil

make these investments for the long run. And we are

and natural gas reserves. We incurred capital costs, including

confident that as these longer-term investments begin to add

acquisitions, of $7.9 billion. This resulted in an all-sources

new reserves and production, they will extend our track

cost of $10.82 for each added barrel of reserves. While these

record of profitable growth.

2003 finding and development costs are above industry

norms and Devon’s historical results, a look beneath the

Deepwater Exploration Gaining Momentum

surface reveals our long-term strategy.

Over the last five years we have enhanced our

During the last three years we have completed three

deepwater Gulf exploration capacity by integrating the

major mergers and acquisitions: Ocean Energy, Mitchell

deepwater leases, seismic libraries and technical capabilities

Energy and Anderson Exploration. Each of these companies

of several companies. Our 2003 discoveries increase our

had significant development projects that Devon assumed. In

excitement about the deepwater Gulf. St. Malo, in the Walker

2003, we invested $900 million in developing already proved

Ridge area of the central Gulf, logged more than 450 net feet

reserves. Simultaneously, we have stepped up our investment

of pay. This well, in which Devon has a 22.5% working

in large, multi-year projects. These include a significant

interest, is Devon’s second discovery in the emerging lower

exploration effort in the deepwater Gulf and offshore West

Tertiary trend. Our first discovery in the trend was Cascade,

Africa as well as long-term investments in Canada. In total,

continued on next page

B e n e a t h t h e S u r f a c e

also in the Walker Ridge area. We plan to drill follow-up wells

Also in 2004, Devon named Brian Jennings chief

to both St. Malo and Cascade in 2004. If these confirmation

financial officer. Brian joined Devon in 2000 and serves as

wells meet expectations, we will begin to plan for their

senior vice president, corporate finance and development,

development. While the discoveries at Cascade and St. Malo

and is a member of the Executive Committee. As CFO, he

have the potential to be meaningful on a stand-alone basis,

assumes responsibility for all financial functions. John, Brian

their significance to Devon is far greater. Through acreage

and Chris reflect the depth of leadership Devon has

acquired in acquisitions, joint ventures and lease sales, Devon

developed throughout the organization.

has assembled a large inventory of lower Tertiary prospects.

In conjunction with the Ocean merger, Devon increased

Our early commitment and involvement with this play has

the number of directors on its board to 13. Joining Devon’s

provided us an outstanding competitive position.

board were former Ocean directors Milton Carroll, Peter Fluor,

Robert Howard and Charles Mitchell. Robert Weaver, who

Financial Strength Deepens

had served since 1999, resigned from the board. I welcome

In Devon’s 2002 Annual Report we pledged to apply the

our new directors and thank Bob Weaver for his dedicated

excess cash we were generating to strengthening our balance

service.

sheet. During 2003 we repaid $500 million in debt and

Also announced in early 2004 were the retirements of

increased cash on hand to $1.3 billion at year-end. We also

two senior executives after lengthy careers with Devon. Mike

refinanced $500 million of existing long-term debt at a very

Lacey, senior vice president, exploration and production,

attractive 2.75% interest rate. Our cash on hand covers

joined the company in 1989. Bill Vaughn, senior vice

100% of debt repayments planned for 2004 and 2005. Given

president, finance, began his career with Devon in 1983. Each

the current oil and gas price environment, we are continuing

was an important contributor to Devon’s success, a valued

to generate cash from operations well in excess of our capital

associate and a good friend.

demands. This will allow us to further reduce debt.

These retirements remind us that change is inevitable.

Depth of Leadership

of which I am most proud. We continue to believe in dealing

John Richels was appointed president of Devon in

with everyone honestly and ethically. We continue to believe

January 2004. John is a member of Devon’s Executive

in the powers of creativity, resourcefulness and hard work to

However, it is the things about Devon that have not changed

Committee. Following the 1998 merger, he led our Canadian

subsidiary, with $8 billion in assets. He is a skilled manager

with a thorough understanding of Devon and our industry.

Chris Seasons previously reported to John and replaces him

as head of our Canadian subsidiary.

uncover hidden opportunities. We continue to believe that to
find success, you must look beneath the surface. ■

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

J. LARRY NICHOLS

Chief Executive Officer and
Chairman of the Board of Directors
March 11, 2004

Five-Year Highlights

Devon’s merger with Ocean Energy occurred on April 25, 2003, and was recorded using the purchase method of accounting.
Therefore, the information presented below includes Ocean’s results from April 25 through December 31, 2003, only.

Year Ended December 31,

1999

2000

2001

2002

2003

LAST YEAR
CHANGE

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

Total revenues (2)
Operating costs and expenses

Earnings (loss) from operations

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

Net results of discontinued operations
Cumulative effect of change in accounting principle

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

Net earnings (loss) per share:

Basic
Diluted

Weighted average common shares outstanding:

Basic
Diluted

Cash flow from continuing operating activities
Operating cash flow from discontinued operations

Net cash provided by operating activities

Cash dividends per common share (3)

December 31,

Total assets
Debentures exchangeable into shares of

ChevronTexaco Corporation common stock (4)

Other long-term debt
Stockholders’ equity
Working capital

PROPERTY DATA (1)

Proved reserves (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
Natural gas liquids (MMBbls)

Total (MMBoe) (5)

10% present value before income taxes (Millions)
10% present value after income taxes (Millions)

1,140
1,309
(169)

2,587
1,431
1,156

2,864
2,672
192

4,316
3,775
541

99
(75)
(193)

39
-

(154)
4
(158)

118
377
661

69
-

730
10
720

164
5
23

31
49

103
10
93

(1.68)
(1.68)

5.66
5.50

0.73
0.72

94
99

452
87
539

127
132

1,479
110
1,589

128
130

1,776
134
1,910

675
(193)
59

45
-

104
10
94

0.61
0.61

155
156

1,726
28
1,754

7,352
4,710
2,642

397
514
1,731

70%
25%
388%

(41%)
(366%)
2,834%

-
16

(100%)
NM

1,747
10
1,737

1,580%
-
1,748%

8.32
8.07

1,264%
1,223%

209
217

3,768
-
3,768

35%
39%

118%
(100%)
115%

0.14

0.17

0.20

1999

2000

2001

2002

2003

LAST YEAR
CHANGE

6,096

6,860

13,184

16,225

27,162

67%

760
1,656
2,521
85

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

760
1,289
3,277
251

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

677
7,903
11,056
293

2%
15%
138%
1,232%

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

661
7,316
209
2,089
22,652
15,921

49%
25%
9%
30%
48%
54%

$
$

$
$
$
$

$
$

Year Ended December 31,

1999

2000

2001

2002

2003

LAST YEAR
CHANGE

Production (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
Natural gas liquids (MMBbls)

Total (MMBoe) (5)

25
295
5
79

37
417
7
113

36
489
8
126

42
761
19
188

62
863
22
228

48%
13%
16%
21%

(1) Years 1999 through 2002 exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002. Devon acquired new assets in Egypt and Indonesia in
the April 2003 Ocean merger that are included in Devon’s 2003 continuing operations. Data has been reclassified to reflect the 2000 merger of Devon and Santa Fe Snyder in accordance
with the pooling-of-interests method of accounting. Revenues, expenses and production in 2003 include only eight and one-fourth months attributable to the Ocean merger; in 2002,
include only eleven and one-fourth months attributable to the Mitchell merger; in 2001, include only two and one-half months attributable to the Anderson Exploration 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 years 1999 and 2000 are not representative of the actual amounts paid by Devon because of the 2000 Santa Fe Snyder transaction
accounted for as a pooling-of-interests merger. For the years 1999 and 2000, Devon’s historical cash dividends per share were $0.20 in each year.

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

B e n e a t h t h e S u r f a c e

(cid:1) A WORKER POSITIONS to complete
installation of a strake on the Red Hawk
cell spar. Strakes deflect ocean currents
to minimize the force exerted on the
spar structure.

Q
A

What have Devon’s mergers and
acquisitions accomplished for the
company, and are there more deals
in your future?

LARRY NICHOLS: We
have used mergers and
acquisitions to achieve
specific strategic
objectives that

could not have
otherwise been achieved. Our conviction that
natural gas was becoming increasingly scarce and
valuable drove us to establish more meaningful
holdings in North America—prior to the recent uplift
in prices. We have achieved that objective. Devon is
among the largest independent producers of North
American natural gas, and we attained that position
at a cost that would be impossible to duplicate
today. As a result, we are generating the highest
levels of cash flow from operations, earnings and
earnings per share in our history.

Another objective achieved through M&A is
enhanced technical capabilities. We have assembled
a highly-skilled workforce with expertise in some of
the most innovative technologies employed in our
industry. Our acquisition of Mitchell Energy in 2002,
gave us the dominant position in the Barnett Shale
and the skills to excel in this play. The PennzEnergy
acquisition in 1999 gave us offshore exploration and
production technology. Our Northstar merger in
1998 gave us thermal heavy oil expertise and the
skills to operate in the Western Canadian
Sedimentary Basin. Today, we have the
ability to pursue opportunities across the
spectrum; from non-conventional
resources such as heavy oil, coalbed
natural gas and black shales to deepwater
exploration in the Gulf and abroad.

While we cannot categorically rule
out the possibility of another acquisition,
Devon is positioned for performance
without additional acquisitions. Past
transactions have allowed us to establish
significant concentrations of high-quality
oil and gas properties in some of the most
desirable areas. We have taken Devon
from a company with only low-risk, low-
growth assets, to one with an enviable
portfolio of low-risk growth projects
balanced by large-scale, high-impact
exploration opportunities. And we have the
technological capabilities to pursue them.
We are no longer dependent upon
acquisitions to grow. ◗

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

SURFACE
WELL HEADS

(cid:1) STEAM-ASSISTED GRAVITY DRAINAGE, or
“SAGD,” utilizes injected steam to recover
heavy oil reserves beneath the surface of the
earth. We are deploying this technology on our
Jackfish project in eastern Alberta, Canada. In
total, Jackfish is expected to add 300 million
barrels of new oil reserves to Devon.

STEAM
CHAMBERS

STEAM(cid:4)

(cid:5)OIL

n
n
o
v
a
t
i
o
n
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

(cid:2) THE MAGNOLIA TENSION-LEG
PLATFORM, when tethered in 4,700
feet of water, will set a water depth
record for platforms of this type.

(cid:3) CONSTRUCTION OF THE RED HAWK cell spar moves
ahead toward a 2004 deployment date. The Red Hawk
facility is designed to handle production of 120 million
cubic feet of natural gas per day.

Rick Mitchell’s 23 years of
oil and gas industry experience
came to Devon in the 2003
merger with Ocean Energy.
As director of Deepwater Well
Engineering and Facilities,
Mitchell is responsible for
overseeing the company’s
deepwater projects.

“Devon and its partners

are using innovation to access
hydrocarbons that were out
of reach with previous
technology,” says Rick. “For
example, we are using the
world’s first cell spar design
(shown here) to shorten the
development cycle of our Red
Hawk field in the deepwater
Gulf.”

(cid:3) A SCALE MODEL
of the Red Hawk cell
spar provides a view
of the completed
facility. Each of its
six mooring cables
will extend more
than a mile to
anchor the massive
floating structure to
the sea floor.

B e n e a t h t h e S u r f a c e

0315pgs1-23_03-16 6/21/04 1:22 PM Page 7

S U R FACE
WELL HEADS

 STEAM-ASSISTED GRAVITY DRAINAGE, or
“SAGD,” utilizes injected steam to recover
heavy oil reserves beneath the surface of the
earth. We are deploying this technology on our
Jackfish project in eastern Alberta, Canada. In
total, Jackfish is expected to add 300 million
barrels of new oil reserves to Devon.

S T E A M
C H A M B E R S

S T E A M

OIL

 CONSTRUCTION OF THE RED HAWK cell spar moves
ahead toward a 2004 deployment date. The Red Hawk
facility is designed to handle production of 120 million
cubic feet of natural gas per day.

Rick Mitchell’s 23 years of
oil and gas industry experience
came to Devon in the 2003
m e rger with Ocean Energ y.
As director of Deepwater We l l
Engineering and Facilities,
Mitchell is responsible for
overseeing the company’s
deepwater pro j e c t s .

“Devon and its partners

a re using innovation to access
h y d rocarbons that were out
of reach with pre v i o u s
t e c h n o l o g y, ” says Rick. “For
example, we are using the
w o r l d ’s first cell spar design
(shown here) to shorten the
development cycle of our Red
Hawk field in the deepwater
G u l f . ”

 A SCALE MODEL
of the Red Hawk cell
spar provides a view
of the completed
facility. Each of its
six mooring cables
will extend more
than a mile to
anchor the massive
floating structure to
the sea floor.

B e n e a t h t h e S u r f a c e

L O O K I N G D E E P E R

Devon Promotes Strong
Stewardship Initiatives

s a multi-national company with operations that touch thousands of lives in
hundreds of communities, Devon is dedicated to environmental stewardship and
improvement of the communities in which we are involved.

The oil and gas industry faces many challenges in its effort to meet the world’s
growing demand for energy. Among them is the preservation of land, water, air and
natural habitats. We are proud of our record of environmental stewardship and we
value the recognition Devon has earned for taking extra steps to preserve and

protect the plants and animals that surround our operations.

Healthy communities allow businesses and their employees to grow and prosper.

Charitable giving and support for education and community projects are at the foundation of
Devon’s effort to be a valued corporate citizen. The well-being of Devon’s 4,000-member
workforce is also a top priority at Devon. The company’s efforts to provide a safe and healthy
workplace have earned a strong record of achievement and recognition.

Respecting our Natural
Environment

Devon is a partner in the U.S.

Environmental Protection Agency’s

Natural Gas STAR Program, a voluntary

effort by government and industry to

reduce natural gas emissions. Partners

in the program have been successful in

reducing methane emissions by more

than 275 billion cubic feet since 1993.

In Canada, Devon is active in the

Voluntary Challenge and Registry, a

partnership between industry and the

Canadian government addressing the

climate change issue. At the elite Gold

Champion level, Devon reports our

annual emissions reductions and

training and awareness initiatives. Since

1994, Devon has implemented more

than 100 emission projects in Canada,

eliminating 1.2 million metric tons of

carbon dioxide emissions. We expect to

eliminate another 700,000 metric tons

this year.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

(cid:3) DEVON WORKS TOGETHER with ranchers in Wyoming’s Powder River Basin to
minimize the environmental impact of drilling and production operations.

(cid:2) IMPROVING HABITAT at the Sundown Island
Bird Sanctuary is a semi-annual volunteer project
for Devon employees in Houston.

community-based initiatives

Health and Safety

includes the Yellow Fish

Road Program, which

The well-being of our employees,

contractors and the public are central to

educates youth and the

Devon’s environmental, health and

Improving our Communities

community at large about water

Devon’s investment in

conservation.

safety philosophy. A tradition of safety is

illustrated by a long history of awards

communities where it has a strong

Internationally, Devon and its

for the safe operation of onshore and

business presence is broad in scope.

employees support local projects where

offshore production facilities and

While the company plans to donate

our business is focused. Those efforts

processing plants. Most recently, in

about $4 million to charity in 2004, our

include the A Casa da Arvore project for

2003, Devon’s offshore operations in the

contributions go far beyond financial

children in impoverished areas of Rio de

Gulf of Mexico received two district

support. Community involvement is a

Janeiro and repairing buildings and

SAFE (Safety Award for Excellence)

core value of the company. This is

providing supplies and furniture for

illustrated by volunteerism and support

village schools in Equatorial Guinea.

honors from the U.S. Department of the
Interior. ■

for local initiatives benefiting youth and

education programs, health and human

services projects, the environment,

cultural events and the arts.

In Oklahoma City, more than 125

Devon employees spend one hour per

week tutoring students at Mark Twain

Elementary School. This school serves

one of the community’s disadvantaged

neighborhoods. Employees serve as

role models and mentors as they help

students with reading and homework.

For the past three years,

employees in Houston have helped

enhance the Sundown Island Bird

Sanctuary in Matagorda Bay near Port

O’Connor, Texas. Volunteers have built

nesting platforms, repaired hurricane

damage and created bird habitats.

In Canada, Devon has a record of

support for education and community

programs. Within the past two years,

the company and its employees have

contributed to efforts ranging from new

construction for higher education to

new preschool facilities for the

underprivileged. Devon’s support for

(cid:3) VOLUNTEER TUTOR and financial accountant Melanie Mercer reads with Mark Twain
elementary student Camisha Brown. Devon teamed with Mark Twain through the
Oklahoma City Public Schools Foundation’s “Partners in Education” program.

B e n e a t h t h e S u r f a c e

EXPLORATION AND PRODUCTION PORTFOLIO

ur merger with Ocean
in early 2003
established Devon as
the largest
independent oil and
gas producer in the
United States. More
importantly, Ocean’s
low-risk development
projects and extensive
exploration portfolio
improved Devon’s

near-term production profile and
enhanced our long-term growth outlook.
During 2003, production from the pro
forma combined company’s oil and gas
properties increased by more than 5%.
In 2004, we expect our property
portfolio to again deliver solid organic
production growth. Approximately $1.6
billion, or almost 70% of our 2004
drilling and facilities budget, will be
applied to the low-risk development
projects that will deliver most of our
2004 production growth.

The lower-risk, near term growth
projects are balanced with measured
exposure to a variety of high-impact
endeavors designed to fuel Devon’s
growth in the second half of this
decade. These longer cycle-time
projects pursue objectives of sufficient
magnitude to provide meaningful
growth—even to a company Devon’s
size. While these longer-term growth
projects require a significant capital
outlay and increase near-term costs,
they are essential to reload our
development inventory for future
growth. Fortunately, Devon’s producing
properties currently provide sufficient
cash flow to fund both near-term
development projects and longer-term
investments.

DEEPWATER GULF DEVELOPMENT
PROJECTS

Nansen/Boomvang Satellite
Discoveries

In the merger with Ocean, Devon

acquired interests in two significant
deepwater producing properties in the
East Breaks area of the Gulf of Mexico.
Nansen and Boomvang, completed in
2002, are in about 3,500 feet of water.
After the merger, Nansen/Boomvang
accounted for approximately 30% of
Devon’s total Gulf of Mexico oil and gas
production.

The Nansen/Boomvang complex

was designed to provide host facilities for
subsequent discoveries on surrounding
acreage. In keeping with this hub-and-
spoke concept, we drilled several satellite
discoveries and began connecting them
to the Nansen/Boomvang complex in
2003. In the first quarter of 2004, we are
tying in two new wells in the Boomvang
area and we expect to add two additional

Reserves
(Net of Royalties)
(MMBoe)

Oil, Gas and NGL
Production
(Net of Royalties)
(MMBoe)

9
8
0
,
2

9
0
6
,
1

2
7
4
,
1

8
5
9

3
6
9

8
2
2

8
8
1

6
2
3 1
1
1

9
7

The Ocean merger and
successful drilling drove
proved reserves to 2.1
billion equivalent barrels
at year-end...

...and increased
production to 228
million equivalent barrels
in 2003.

recent discoveries in the third quarter.
These satellites add new oil and gas
reserves and help maintain a high level
of production through these facilities.
Devon’s current share of production from
Nansen/Boomvang is about 42,000
barrels of oil equivalent per day.

Red Hawk and Magnolia
Moving Ahead

In addition to the established

Nansen/Boomvang complex, Ocean
had two other deepwater development
projects under construction at the time

of the merger. Red Hawk, in 5,300 feet
of water, and Magnolia, in 4,700 feet,
both lie in the Garden Banks area of
the Gulf of Mexico. Devon maintains a
50% working interest in Red Hawk and
a 25% interest in Magnolia.

Red Hawk, discovered in 2001,
will employ the world’s first cell spar,
the latest generation of the floating
spar concept. Red Hawk’s floating hull
comprises six steel tubes, or cells,
surrounding a seventh center tube. The
top of the hull will ride above the water
and support the deck. Red Hawk’s

component construction allowed it to
be economically fabricated at a site on
the Gulf Coast, relatively close to its
eventual mooring place. This
innovative approach reduced the
required development cycle-time,
thereby improving the rate of return.

Devon and its partner drilled,

completed and tested the two initial
Red Hawk gas wells in 2003. The wells
await subsea tie-in to the spar. We
expect first production in the third
quarter of 2004, with Devon’s share in

continued on next page

(cid:2) THE HULL for the Magnolia tension
leg platform is shown under
construction in a fabrication yard in
Korea. Following its completion in late
2003, the hull was shipped to Corpus
Christi, Texas, for mating with the deck.
We expect Magnolia to bring Devon
more than 10,000 barrels a day of new
oil production.

In today’s oil and gas price
environment, Devon is
generating large amounts of
excess cash. How do you plan
to deploy the surplus?

BRIAN
JENNINGS,
Senior Vice
President and
Chief Financial

Officer: As
evidenced by our
record earnings and cash flow in 2003, this is
a very good time for Devon and the
independent exploration and production
sector. Oil and gas supply and demand
fundamentals currently favor producers.
However, commodity prices can change
quickly. Consequently, we must take
advantage of the current environment and
seize this opportunity to further strengthen
our balance sheet.

In spite of the rapid progress we’ve

made over the last year in building Devon’s
financial strength, we still view debt
repayment as a top priority. At year-end 2003
we had accumulated $1.3 billion in cash
earmarked to retire about $340 million of debt
in 2004 and $920 million in 2005. We expect
to generate excess cash again in 2004 and
believe it is prudent to begin to prepare for
our 2006 debt maturities. However, as we
become satisfied that we have an ample cash
cushion for future debt retirement, we will
consider alternative uses of cash such as
additional dividend increases and
repurchasing stock. ◗

O
p
e
r
a
t
i
o
n
s
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

B e n e a t h t h e S u r f a c e

EXPLORATION AND PRODUCTION PORTFOLIO

DEEPWATER GULF DEVELOPMENT
PROJECTS

Nansen/Boomvang Satellite
Discoveries

In the merger with Ocean, Devon

The Nansen/Boomvang complex

Reserves
(Net of Royalties)
(MMBoe)

Oil, Gas and NGL
Production
(Net of Royalties)
(MMBoe)

9
8
0
,
2

9
0
6
,
1

2
7
4
,
1

8
5
9

3
6
9

8
2
2

8
8
1

6
2
3 1
1
1

9
7

The Ocean merger and
successful drilling drove
proved reserves to 2.1
billion equivalent barrels
at year-end...

...and increased
production to 228
million equivalent barrels
in 2003.

Red Hawk and Magnolia
Moving Ahead

In addition to the established

Nansen/Boomvang complex, Ocean
had two other deepwater development
projects under construction at the time

Devon and its partner drilled,

completed and tested the two initial
Red Hawk gas wells in 2003. The wells
await subsea tie-in to the spar. We
expect first production in the third
quarter of 2004, with Devon’s share in

continued on next page

In today’s oil and gas price
environment, Devon is
generating large amounts of
excess cash. How do you plan
to deploy the surplus?

BRIAN
JENNINGS,
Senior Vice
President and
Chief Financial

In spite of the rapid progress we’ve

O
p
e
r
a
t
i
o
n
s
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

B e n e a t h t h e S u r f a c e

EXPLORATION AND PRODUCTION PORTFOLIO

the range of 50 to 70 million cubic feet
of gas per day. As with Nansen/
Boomvang, Red Hawk is designed to be
a central processing facility serving
future discoveries in the area.

Production facilities for the 1999

Magnolia discovery are nearing
completion. Magnolia’s 10,000 ton hull,
completed in late 2003, was fabricated in
Korea and towed by sea to a yard on the
Texas coast. Final construction of this
tension-leg platform is under way with
field installation scheduled for late 2004.
We initially plan to bring on two of the
nine expected producing wells near year-
end. Devon’s share of Magnolia’s oil and
gas production is expected to total
10,000 to 12,000 oil equivalent barrels
per day.

INTERNATIONAL DEVELOPMENT
PROJECTS

Zafiro Field Gets Bigger

The most significant producing
property in Ocean’s portfolio was its
interest in the Zafiro field, offshore
Equatorial Guinea. Zafiro was
discovered in 1995. At the time of the
merger in April 2003, Devon’s share of
production was approximately 35,000
barrels per day. In July 2003, we
ramped up production dramatically by
bringing on new wells in the Zafiro
Southern Expansion Area. Zafiro oil is
produced into floating production,
storage and offloading vessels, or
FPSOs. With the addition of the new
Serpentina FPSO, field-wide production
climbed to a record 302,000 equivalent
barrels of oil per day with Devon’s share
topping 57,000 barrels per day.

Panyu Production on Stream

Another source of 2004 production

growth is a Devon-operated oil
development project in the South China
Sea. Late in 2003, we culminated this
multi-year development with initial
production from the twin Panyu
platforms. Devon’s share of Panyu
production should average about
15,000 barrels per day in 2004.

ACG Field Awaits Main Export
Pipeline Completion

The 1,100-mile long, one million
barrel per day oil pipeline connecting
the Caspian Sea and the Mediterranean
is under construction. Its expected
completion in 2005 will connect the 4.7
billion barrel ACG field in Azerbaijan to
world markets. This will allow
production from this super-giant oil field
to begin ramping up dramatically.
Devon’s share of oil production from our
5.6% interest in the ACG field is
expected to peak in 2008 or 2009, at
more than 50,000 barrels per day.

continued on page 16

North American
Natural Gas
Production
(BCF)

Marketing and
Midstream Margin*
($ Millions)

6
5
8

1
6
7

9
8
4

7
1
4

5
9
2

Devon increased North
American natural gas
production to a record
856 billion cubic feet in
2003.

6
8
2

1
9
1

5
2

4
2

0
1

Greater gas throughput
and higher gas and gas
liquids prices increased
marketing and midstream
margin by 50% in 2003.

* Marketing and midstream
revenues less operating costs

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Q
A

Devon’s Canadian production
declined in 2003. Can the
company grow its Canadian
production in the future?

JOHN RICHELS,
President: Yes,
we can. In 2003,
we replaced

110% of our
Canadian
production with
new reserves and we are allocating about
$750 million of our 2004 capital budget to
Canada. This should translate into
significant production growth in 2004.

Looking beyond 2004, Devon has a
tremendous base from which to explore for
new oil and gas reserves. We have a large
inventory of infill drilling opportunities on
our current producing properties in
Canada. For example, in many parts of the
Deep Basin where Devon is one of the
largest producers, our well density is lower
than most of our competitors. This
provides us with a source of low-risk
reserve and production growth for the
future. Furthermore, we hold some 10
million net undeveloped acres in Canada—
the largest position of any U.S.-based
independent. The growth opportunities
represented by this acreage position are
reflected in our 2004 capital budget with
about $250 million devoted to Canadian
exploration.

Further out on the growth curve are
Devon’s Jackfish thermal heavy oil project
and Mackenzie Delta gas. Jackfish is
expected to start producing in 2006 or
2007 with production reaching 35,000
barrels per day in 2008. These wells have
very long productive lives and in aggregate
represent 300 million barrels of potential
recoverable reserves. Our 2002 gas
discovery in the Mackenzie Delta awaits
construction of a pipeline that could be
built before the end of the decade. Since
neither of these projects is contributing to
current production or reserves, they are
sources of future growth in Canada. ◗

Liquids
from Gas
A

s natural gas flows from the
underground rock formations
from which it is produced, it often
contains varying quantities of
natural gas liquids. Natural gas
liquids, also known as NGLs, include
ethane, propane, butane, and natural
gasoline. These byproducts are used for
everything from feedstock for
manufacturing chemicals to fuel for
backyard grills.

Devon’s wells in north Texas can

produce as much as four to five gallons
of recoverable NGLs from every
thousand cubic feet of gas produced.
Along the Texas Gulf Coast, recovery
rates are generally two to three gallons
per thousand cubic feet. Many basins in
western Canada also produce liquids-
rich gas.

NGLs are generally more valuable

when extracted and sold on a stand-
alone basis than when left in the gas
stream and sold as natural gas.
Consequently, an important part of
Devon’s marketing and midstream
business is the extraction and sale of
NGLs.

Devon primarily employs the
cryogenic method of extracting NGLs.
This requires cooling the natural gas
stream to as low as minus 150oF. As the
temperature is lowered, natural gas
liquids condense and separate from the
methane gas. The extracted NGLs are
then shipped to customers by truck, rail
and pipeline. ■

B e n e a t h t h e S u r f a c e

FRACTIONATION TOWERS at Devon’s Bridgeport, Texas, gas plant extract liquids from the

natural gas stream. Devon is one of the largest gas processors in North America.

(cid:2) A DRILLING RIG shown at twilight drills a
Permian Basin well. Long-lived reserves, typical
of the Permian Basin, provide Devon with a
stable source of cash flow.

How does marketing and midstream
contribute to the overall success of
the company?

Q
A

DARRYL SMETTE,
Senior Vice President,
Marketing and
Midstream: By
owning gas processing
assets in areas where we
have significant production, we can assure access to
ready markets and timely connection of our wells to
gathering and processing facilities. This adds stability
and predictability to our oil, natural gas and liquids
production. Owning significant midstream assets also
enhances the company’s overall economic returns.

In 2003, Devon’s marketing and midstream

operations delivered outstanding results. We
increased revenues to $1.5 billion, 46% ahead of
2002. Our operating margin of $286 million
was 50% more than in 2002. Higher natural
gas and natural gas liquids prices combined
with a 25% increase in natural gas
throughput volumes led to these results. We
also disposed of three non-core assets and
improved administrative efficiency by
consolidating personnel into our Oklahoma
City headquarters. This has allowed us to
improve our effectiveness and reduce costs.
We expect 2004 to be another very
profitable year for the marketing and
midstream division. ◗

(cid:3) THE HAVRE PIPELINE,
managed by Devon, transports
gas from our Bear Paw field in
north central Montana.
Devon owns interests in more
than 13,000 miles of pipelines.

(cid:2) DRILL BITS are designed to fit many well configurations
and applications. Of more than 2,100 successful wells

Devon drilled in 2003, 87% were development wells in
North America. Our extensive inventory of low-risk

development locations is a stable source of oil and
gas production growth.

(cid:2) CORE SAMPLES enable
geoscientists to better
understand underground
reservoir characteristics.
Effective reservoir
management enhances
the reliability and
predictability of Devon’s
production profile.

Joe Huber came to Devon
through the 2000 merger with
Santa Fe Snyder. He had been
with Santa Fe since 1990. As
foreman, Joe supervises field
operations and production
from the Indian Basin field in
southeast New Mexico.

“As a 19-year veteran of

the energy industry, I’m
pleased to work for a company
with the strength and stability
of Devon.”

(cid:6) OUR PANYU PROJECT IN CHINA will add about
15,000 barrels of oil per day to 2004 production. First
production from Panyu was five years after the initial
discovery in 1998. In 2003, Devon invested $500 million
in long cycle-time projects, such as Panyu. These
investments in future production and reserve additions
help to stabilize Devon’s long-term production outlook.

S
t
a
b

i
l
i
t
y
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

B e n e a t h t h e S u r f a c e

(cid:2) A DRILLING RIG shown at twilight drills a
Permian Basin well. Long-lived reserves, typical
of the Permian Basin, provide Devon with a
stable source of cash flow.

How does marketing and midstream
contribute to the overall success of
the company?

Q
A

In 2003, Devon’s marketing and midstream

(cid:3) THE HAVRE PIPELINE,
managed by Devon, transports
gas from our Bear Paw field in
north central Montana.
Devon owns interests in more
than 13,000 miles of pipelines.

(cid:2) DRILL BITS are designed to fit many well configurations
and applications. Of more than 2,100 successful wells

Devon drilled in 2003, 87% were development wells in
North America. Our extensive inventory of low-risk

development locations is a stable source of oil and
gas production growth.

“As a 19-year veteran of

the energy industry, I’m
pleased to work for a company
with the strength and stability
of Devon.”

S
t
a
b

i
l
i
t
y
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

B e n e a t h t h e S u r f a c e

EXPLORATION AND PRODUCTION PORTFOLIO

THE BARNETT SHALE; MOVING
OUTSIDE THE CORE

The Barnett Shale in the Fort

Worth Basin of north Texas was the
crown jewel of the Mitchell acquisition
and is Devon’s largest asset. In just a
handful of years, the Barnett Shale has
grown to become the largest gas field in
Texas and one of the largest in North
America. We have increased production
from the Barnett Shale by two-thirds
since announcing the Mitchell
acquisition in 2001. At year-end 2003, it
was producing about 575 million
equivalent cubic feet of gas per day for
the company.

The Barnett Shale is a “tight”
formation. After drilling, wells must be
fracture stimulated to provide paths for
the gas to flow into the wellbore. The
portion of the field we refer to as the
core area is characterized by a
limestone barrier at the base of the
shale. This barrier stops the hydraulic
fractures from penetrating a deeper,
water-bearing zone. Most of Devon’s
1,600 producing Barnett Shale wells are
within this core area.

While most of our current Barnett
Shale production comes from within it,
the core area represents just 120,000 of
Devon’s 550,000 net acres in the field.
In late 2002 and 2003, Devon began
experimenting with horizontal drilling as
an approach to avoid the water and
move production outside the core. (See
inset story on horizontal drilling on next
page.) We are encouraged by our
horizontal drilling results so far.
However, with horizontals representing
fewer than 5% of Devon’s Barnett Shale
wells, we have much to learn. It took
Devon, and Mitchell Energy before us,
years to perfect the drilling and
completion methods that are most
effective within the core area. This
process is only beginning outside its

boundaries. Including horizontal and
vertical wells, we plan to drill about 225
Barnett wells in 2004, with more than 50
planned for outside the core.

CANADIAN OIL SANDS…AN
INVESTMENT IN THE FUTURE

Devon launched a major Canadian
thermal heavy oil development project in
2003. We plan to invest some $400
million over several years in our 100%
owned Jackfish project. Western
Canada’s oil sands, or bitumen
deposits, are vast, and Devon holds
leases on about 150,000 net acres.
Shallow bitumen deposits can be mined
at the surface. Others, like Jackfish, are
too deep to mine and employ Steam-
Assisted Gravity Drainage (SAGD) to
extract the bitumen. Devon operates the
world’s longest-running SAGD facility at
Dover, located north of Jackfish.

At Jackfish, we will initially drill 35
pairs of wells into the tar-like bitumen.
Steam injected into the upper wells
heats the bitumen and allows it to drain
into the lower producing wells along
with water condensed from the steam.
At the surface facilities, bitumen is
separated from the water and blended
with light crude so it can be pumped
through pipelines to market.
Government approvals are pending, and
we expect to begin constructing the
Jackfish facilities in late 2004. We
anticipate reaching full production of
35,000 barrels per day in 2008.

GULF OF MEXICO EXPLORATION

Devon has an interest in 544
exploration blocks in the deepwater Gulf
of Mexico—the largest inventory of any
independent producer. Because

continued on page 18

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

It has been almost a year since
the Ocean merger. Have the
expected synergies of the
merger been realized and is
the integration with Ocean
complete?

MARIAN J. MOON,
Senior Vice
President,
Administration:
We have

substantially
completed the
integration of Ocean and have begun to
capture the synergies. At the time of the
merger, most of Ocean’s employees were in
Houston. Because Devon’s Gulf of Mexico
and international divisions were already
located in Houston, we integrated the Ocean
staff without extensive employee relocations.
During this process, we consolidated all the
Houston-area Devon and Ocean employees
into Devon’s downtown offices. As part of
the integration, about 360 full-time positions,
with associated annual costs of $30 to $35
million, were eliminated. Ocean also had
some long-term contracts for various
services that, when eliminated, will generate
additional savings over time. Less obvious
synergies resulting from Devon’s larger size,
such as increased purchasing power,
superior access to capital and more effective
marketing of our oil and gas are also being
achieved.

General and administrative expense per

barrel of oil and gas produced is one
measure of the synergies of the merger.
Based on our full-year forecast, we expect
our general and administrative expense in
2004 to be about $1.20 per equivalent barrel
of production. This compares with actual
general and administrative expense of $1.35
per barrel in 2003. These savings are being
achieved in spite of general upward pressure
on employment costs. ◗

Beneath the Surface, Horizontally
A

bove ground, horizontal wells appear much like the more
common vertical wells. The same drilling rigs can drill
both types. It’s deep beneath the surface where things
change. At a pre-determined depth, the vertical wellbore
is steered in a mild arc until it eventually runs parallel to

Drilling costs are usually higher for a horizontal well, but better
oil and gas recoveries can more than offset the incremental
costs. One horizontal well may take the place of two, three or
even more vertical wells. This also means that fewer surface
locations are necessary. This is an advantage in populated or
environmentally sensitive areas, where minimal surface impact
is required. Offshore, directional drilling, of which horizontal
drilling is a variant, is essential. Multiple offshore wells are often
drilled from and produced through a single fixed platform.

the surface. Horizontal drilling is possible because seemingly
rigid steel pipe is actually quite flexible over long spans.
Specialized down-hole cutting tools and computerized
monitoring systems make it possible to steer the drilling with
remarkable precision.

Horizontal drilling isn’t new, but 25 years of technological
improvements have made it more reliable and cost effective. An
advantage of horizontal drilling is that it penetrates more
reservoir rock than would be possible with a typical, vertical
well. Therefore, more oil or gas is recovered from each well.

Devon will drill more than 100 horizontal wells this year in

its Barnett Shale gas field in north Texas. We believe that
horizontal drilling may be a key to unlocking the potential of our
430,000 net acres outside the core Barnett Shale producing
area. ■

B e n e a t h t h e S u r f a c e

EXPLORATION AND PRODUCTION PORTFOLIO

individual deepwater exploration wells
require a significant capital investment,
we utilize partnerships and joint
ventures to limit our exposure to any
single project. In this way we gain
access to a wide variety of projects and
play types without undue risk. Devon
generally limits its exposure to
participation in six to eight deepwater
exploration wells each year. In 2004,
three of our deepwater Gulf exploration
wells are designed to further delineate
discoveries made in 2002 and 2003.

The Emerging Lower Tertiary Trend
In last year’s annual report we

discussed our deepwater Gulf of
Mexico discovery called Cascade. While
Cascade appears to be significant,
quantifying it further will require more
drilling. In 2003, Devon drilled another
deepwater discovery approximately 50
miles from Cascade called St. Malo.
Both wells are in the Walker Ridge area.
These two wells and other recent
industry discoveries underpin an
emerging exploratory play becoming
known as the lower Tertiary trend.

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)

St. Malo, in which Devon has a
22.5% working interest, encountered
more than 450 net feet of oil pay over a
gross interval of 1,400 feet. In addition
to those impressive figures, the lateral
extent of the reservoir looks to be very
large as well. Additional drilling will
define just how large. Devon and our

Net Undeveloped
Acreage
(Millions of Acres)

Capital
Expenditures for
Exploration &
Development
($ Billions)

6
2

6
.
2

2
2

1
2

6
1

4
1

5
.
1

3
.
1

8
.
0

5
.
0

Devon has nearly
doubled its inventory of
net undeveloped
acreage...

...and increased capital
expenditures for
exploration and
development five-fold
since 1999.

partners in St. Malo plan to drill an
appraisal well in 2004. If that well and
other delineation steps continue to
encourage us, we will begin planning for
field development. Because deepwater
projects are multi-year undertakings—
St. Malo is in 6,900 feet of water—first
production is at least four years away.
We hope to begin booking reserves for
St. Malo in 2004 or 2005.

In 2004, Devon will also participate

in an appraisal well to our 2002
Cascade discovery. Our early success
at Cascade allowed us to establish a
significant position in this emerging play.
We have assembled 19 additional lower
Tertiary prospects. In addition to
delineating our discoveries at Cascade
and St. Malo, we expect to test at least
two other lower Tertiary prospects
during 2004.

About 70 of our more than 500
deepwater acreage blocks are being
earned through a joint venture with
ChevronTexaco. We are currently drilling
the last of the four earning wells in the
joint venture; the Jack well will test
another lower Tertiary target in the

1993

1994

1995

1996

1997

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

219
1,403
24
477
2,100

29
180
3
62

17.03
2.04
12.61
14.51

4.63

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

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Walker Ridge area, close to St. Malo.
Although Jack will complete Devon’s
obligation under the terms of the joint
venture, we expect to continue
exploring with ChevronTexaco on this
acreage in the future.

encountered 110 feet of net pay below
17,000 feet. Devon has a 30% working
interest in this well, which is expected
to begin producing mid-year 2004.
Devon plans to participate in as many
as 10 deep shelf prospects in 2004.

Drilling Deeper on the Shelf

Although it’s a mature producing

INTERNATIONAL EXPLORATION

region, the Gulf of Mexico’s shallow shelf
still has life left in it. In 2003, Devon’s
11,000-foot Grays discovery on
Galveston 424 resulted in three gas wells
that came on line in February 2004.
Devon’s share of production from Grays
came in at more than 25 million cubic
feet per day. Devon will test two other
prospects similar to Grays in 2004.

Exploration of deep formations

beneath the shelf is gaining increasing
attention within the industry. The “deep
shelf” generally refers to wells drilled
below 15,000 feet. Recent advances in
seismic technology and federal royalty
incentives have stimulated deep shelf
exploration. In early 2004, Devon made
its first deep shelf discovery. The Tikal
prospect, Eugene Island 142,

Outside North America, Devon’s
exploration inventory includes several
high-potential licenses offshore West
Africa and Brazil. To limit risk, Devon is
reducing its interests in several licenses
through joint ventures. In 2004, we plan
to drill seven exploratory wells on lease
blocks in Angola, Equatorial Guinea,
Nigeria and Brazil. While the chances of
success for any one of these prospects
is low, the size of potential discoveries
in these areas justifies the risk. In
aggregate, these wells will expose
Devon to prospects with gross unrisked
reserve potential of several billion
barrels. ■

Devon’s finding and
development costs were high
last year and will lead to higher
DD&A in 2004. When will these
results improve?

LARRY NICHOLS:
Devon’s 2003 all-
sources finding and
development costs
were $10.82
per equivalent barrel.
This was about 30%
above our five-year average of $8.25 per
barrel. Our forecasted increase in unit
depreciation, depletion and amortization
expense for 2004 is largely a function of these
higher finding and development costs.
The multi-year time horizon of our
exploration investments makes it difficult to
forecast finding costs for a particular year.
That’s because discoveries like St. Malo and
Cascade in the Gulf of Mexico and Tuk M-18
in the Mackenzie Delta do not immediately
increase reserves. We are optimistic that we
can begin booking some of these reserves
within the next 12 to 18 months, but it’s
premature to say how this will influence 2004
results. However, we are confident that over
time, Devon’s finding and development costs
will be highly competitive with our peers, as
they have been throughout most of our
history. ◗

1998

1999

2000

2001

2002

2003

GROWTH RATE

5–YEAR COMPOUND 10–YEAR COMPOUND

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

661
7,316
209
2,089
22,652

62
863
22
228

25.63
4.51
18.65
25.88

5.63

32%
38%
58%
37%
75%

25%
35%
49%
33%

16%
20%
18%
18%

10%
26%
40%
19%
36%

9%
23%
35%
17%

7%
10%
4%
8%

B e n e a t h t h e S u r f a c e

(cid:1) GAS CONTROLLER, Rick Martin,
in Oklahoma City, monitors
transmission of natural gas on a
real-time basis.

Q
A

What will be your focus as
Devon’s new president?

JOHN RICHELS:

Continuous

improvement is a

top priority.

We know that to be

competitive and to

perform at the highest levels, we can never

accept the status quo. As president, I will

work to communicate the importance of this

to every Devon employee. Growth alone is

not an objective. Building shareholder value

is our overarching goal. For Devon to

continue to excel, every employee must know

how their efforts to be more productive

contribute to achieving this goal.

Improving technology is one dimension

of continuous improvement. As managers,

we can enable productivity gains by making

the latest and best technologies available to

all our employees. This requires a willingness

to invest capital, but it also requires a

willingness to encourage innovative thinking.

One of my challenges is to assure that those
conditions are met. ◗

(cid:1) COMPUTER
WORKSTATIONS
bring 3-D imaging
right to the
explorationist’s
desktop.

(cid:3) THREE-DIMENSIONAL seismic
imaging is an invaluable tool for
Devon’s explorationists. Devon is
utilizing the latest 3-D data
acquisition and processing
technologies to see clearer and
deeper.

T
e
c
h
n
o
o
g
y
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

(cid:2) WELLBORE LOGS
can indicate the presence

of oil and gas beneath the

surface.

Cathy Pocock, senior Gas Sales
representative in the Natural Gas
Sales Department in Oklahoma City,
joined Devon in September 2003.
She is responsible for
marketing Devon’s gas production
from areas including the Rocky
Mountains, San Juan Basin and
Permian Basin.

Cathy appreciates Devon’s
investment in technology. She says,
“Immediate electronic access to
multiple markets enables us to keep
Devon’s oil and gas flowing while
maximizing our revenues.”

(cid:2) THE TRANSOCEAN
DISCOVERER SPIRIT
drills Devon’s 2003 St.
Malo discovery in the
Gulf of Mexico. Drillships
are generally deployed
in water depths greater
than 5,000 feet.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

B e n e a t h t h e S u r f a c e

(cid:1) GAS CONTROLLER, Rick Martin,
in Oklahoma City, monitors
transmission of natural gas on a
real-time basis.

Q
A

What will be your focus as
Devon’s new president?

JOHN RICHELS:

Continuous

improvement is a

top priority.

We know that to be

competitive and to

perform at the highest levels, we can never

accept the status quo. As president, I will

work to communicate the importance of this

to every Devon employee. Growth alone is

not an objective. Building shareholder value

is our overarching goal. For Devon to

continue to excel, every employee must know

how their efforts to be more productive

contribute to achieving this goal.

Improving technology is one dimension

of continuous improvement. As managers,

we can enable productivity gains by making

the latest and best technologies available to

all our employees. This requires a willingness

to invest capital, but it also requires a

willingness to encourage innovative thinking.

One of my challenges is to assure that those
conditions are met. ◗

(cid:1) COMPUTER
WORKSTATIONS
bring 3-D imaging
right to the
explorationist’s
desktop.

T
e
c
h
n
o
o
g
y
.

B
e
n
e
a
t
h

t
h
e
S
u
r
f
a
c
e

(cid:2) WELLBORE LOGS
can indicate the presence

of oil and gas beneath the

surface.

Cathy appreciates Devon’s
investment in technology. She says,
“Immediate electronic access to
multiple markets enables us to keep
Devon’s oil and gas flowing while
maximizing our revenues.”

(cid:2) THE TRANSOCEAN
DISCOVERER SPIRIT
drills Devon’s 2003 St.
Malo discovery in the
Gulf of Mexico. Drillships
are generally deployed
in water depths greater
than 5,000 feet.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

B e n e a t h t h e S u r f a c e

Devon’s 2004 Exploration, Development
and Facilities Budget is $2.1 - $2.5 Billion

10%

21%

Devon’s Proved Oil and Gas Reserves
at December 31, 2003, Totaled
2.1 Billion Equivalent Barrels

15%

10%

32%

28%

47%

37%

Operating Statistics by Area

PERMIAN

MID-

ROCKY

CONTINENT(1) MOUNTAINS

GULF
COAST(1)

U.S.
OFFSHORE

TOTAL
U.S.

CANADA INTERNATIONAL COMPANY

TOTAL

Producing Wells at Year-End

9,585

5,252

5,243

4,315

1,318

25,713

6,803

511

33,027

2003 Production (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Total (MMBoe) (2)

Average Prices
Oil price ($/Bbl)
Gas price ($/Mcf)
NGLs price ($/Bbl)
Oil equivalent price ($/Boe) (2)

Year-End Reserves (Net of royalties)

Oil (MMBbls)
Gas (Bcf)
NGLs (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)

9
56
2
21

$ 29.39
$
4.65
$ 18.63
$ 27.62

92
351
17
167

$ 1,825
$

1
179
11
41

25.11
4.22
15.92
22.91

4
1,707
102
390

2
107
1
21

21.33
3.82
9.73
22.29

21
1,021
8
200

2
121
2
24

29.95
5.13
22.05
29.99

14
1,103
29
227

17
126
1
39

27.23
4.78
23.42
27.91

81
702
5
203

31
589
17
146

27.64
4.50
17.31
26.02

212
4,884
161
1,187

14
267
5
63

23.54
4.57
23.08
26.25

148
2,297
48
579

17
7
-

23.64
3.47
21.45
23.45

301
135

323

62
863
22
228

25.63
4.51
18.65
25.88

661
7,316
209
2,089

3,481

2,128

2,506

3,405

13,345
9,503

5,930
4,123

3,377
2,295

22,652
15,921

Producing
Undeveloped

330
506

677
405

499
885

641
538

473
1,548

2,620
3,882

2,335
9,935

323
12,051

5,278
25,868

Wells Drilled During 2003

308

428

366

167

1,325

850

2,229

2003 Exploration, Development and
Facilities Expenditures (Millions) (4)

Estimated 2004 Exploration, Development &

129

398

135

232

688

1,582

741

331

2,654

Facilities Expenditures (Millions) (5)

$105-135 305-365 105-135 255-310

460-505 1,230-1,450

690-830

220-260 2,140-2,540

(1) Properties in east Texas and north Louisiana, previously included in the Mid-Continent area, are now included in the Gulf Coast area.
(2) Gas converted to oil at the ratio of 6Mcf:1Bbl. 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 SFAS No. 69, Disclosures about Oil and Gas Producing Activities.

(4) Excludes $53 million spent on marketing and midstream assets and non-cash asset retirement costs.
(5) Excludes $90 to $100 million expected to be spent on marketing and midstream assets.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Committed to Strong
Corporate Governance

rust in corporate business has been tested in

Our Code of Conduct

recent years. Too many examples of unethical, and

Also available for review on our website is Devon’s Code

in some cases illegal, behavior led to a decline in

of Business Conduct and Ethics. This code applies to each of

investor confidence. Although we firmly believe the

the company’s directors, officers and employees.

offenders represent a small minority, we also

Supplementing the code, Devon has adopted numerous policies

recognize the importance of restoring the public’s

addressing specific elements of business ethics and required

trust. Devon has taken steps to emphasize our

conduct. The code and policies encompass critical aspects of

commitment to maintain a culture of the highest

corporate behavior including protection of confidential

ethical and professional standards with sound

information, trading in Devon’s securities, accounting practices,

corporate governance. These actions, however, required no

conflicts of interest, receipt of gifts and abuse of drugs and

material changes to our long-

held beliefs and established

business practices. We simply

documented and formalized

Devon’s corporate controls and

procedures that have been in

place throughout our history.

Guidelines for
Governance

The Nominating and

Governance Committee of

In November 2003,
the board of directors
formally adopted
Devon’s Corporate
Governance Guidelines.

alcohol. Acknowledgement of the

code and compliance with its

provisions are conditions of

employment at Devon.

The code also addresses the

importance of full and open

disclosure of financial and non-

financial information. In that regard,

Devon has established a Disclosure

Committee responsible for

disclosure practices. Devon’s

Disclosure Committee plays a vital

Devon’s board of directors developed and recommended

role in assuring that the company is in full compliance with the

guidelines for the board. In November 2003, the board of

reporting and executive certification requirements of The

directors formally adopted Devon’s Corporate Governance

Sarbanes-Oxley Act of 2002.

Guidelines. These guidelines provide a framework for

monitoring the effectiveness of the board and its committees as

Role of the Audit Committee

they oversee achievement of Devon’s objectives. Central to

In addition to its emphasis on financial reporting,

those objectives is long-term enhancement of shareholder value

Sarbanes-Oxley imposed responsibilities on the Audit

while taking into account the interests of all Devon’s

Committee of the board of directors. These responsibilities

stakeholders. The guidelines address the qualifications and

include selection, appointment, compensation and evaluation of

responsibilities of directors, as well as procedures and policies

the company’s independent auditors. The Audit Committee also

relevant to carrying out the board’s responsibilities.

reviews significant accounting principles and policies, the

In addition to overseeing corporate governance, the

adequacy of internal controls and has oversight of the integrity

Nominating and Governance Committee of Devon’s board of

of the company’s financial statements and reporting system.

directors is also responsible for recruiting, recommending and

All members of the Audit Committee must be independent

nominating directors to the board. We encourage shareholders

directors, as defined by the Securities and Exchange

to review Devon’s Corporate Governance Guidelines and the

Commission, and one member must be a financial expert.

Nominating and Governance Committee Charter on our

Shareholders are encouraged to review the Audit Committee

website at www.devonenergy.com.

Charter, which is also available on Devon’s website.

B e n e a t h t h e S u r f a c e

■
Key Property Highlights

• Produces gas from the Eagle formation at 800' to 2,000'.
• 25.5 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 97 wells.
• Acquired 2-D and 3-D seismic.
2004 Plans
• Drill 75 wells.
• Evaluate seismic for additional drilling

opportunities.

BB Powder River Coalbed Natural Gas

Permian
Permian

Mid-Continent
Mid-Continent

AA Southeast New Mexico

A A Barnett Shale

Profile
• 65% average working interest in 574,000 acres in

southeast New Mexico.

• Key fields include Indian Basin, Ingle Wells and

West Red Lake.

• Produces oil and gas from multiple formations

at 1,500' to 12,500'.

Profile
• 550,000 net acres (120,000 within core area)

in the Fort Worth Basin of north Texas.
• 95% average working interest in core.
• 80% average working interest outside core.
•
Initial position obtained in 2002 merger.
• Produces gas from the Barnett Shale formation

• 57.9 million barrels of oil equivalent reserves

at 6,500' to 8,500'.

at 12/31/03.
2003 Activity
• Drilled and completed 33 gas wells.
• Drilled and completed 40 oil wells.
• Recompleted 21 wells.
2004 Plans
• Drill 25 gas wells.
• Drill 60 oil wells.
• Evaluate recompletion opportunities.

BB West Texas

Profile
• 40% average working interest in 1.1 million acres

in west Texas.

• Key fields include Ozona, Reeves, Anton-Irish

and Wasson.

• Produces oil and gas from multiple formations

at 2,500' to 18,000'.

• 109.3 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 12 gas wells.
• Drilled and completed 27 oil wells.
• Recompleted 17 wells.
2004 Plans
• Drill 21 gas wells.
• Drill 37 oil wells.
• Recomplete 17 wells.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

• 297.4 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled 359 wells within core area, including:

325 vertical infill wells.
34 horizontal wells.

• Drilled 18 horizontal wells outside core area.
• Refractured 66 wells.
• Acquired 3-D seismic and acreage.
2004 Plans
• Drill 163 wells within core area, including:

113 vertical infill wells.
50 horizontal wells.

• Drill 60 horizontal wells outside core area.
• Refracture 34 wells.
• Acquire additional 3-D seismic and acreage.

Rocky Mountains
Rocky Mountains

AA Bear Paw

Profile
• 70% average working interest in 700,000 acres in

north central Montana.
• Obtained in 2003 merger.

Profile
• 73% average working interest in 350,000 acres in

northeastern Wyoming.
Initial position obtained in 1992 acquisition.

•
• Produces coalbed natural gas from the Fort Union

Coal formations at 300' to 2,000'.

• 14.8 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled 86 coalbed gas wells.
• Connected 10 well Big George pilot to sales

at Juniper Draw.

• Assumed operatorship of Rough Draw field.
2004 Plans
• Drill 110 coalbed gas wells, including

85 deep Wyodak and Big George wells.
• Recomplete approximately 50 coal wells.
•

Install compression at 26 central delivery points.

CC Washakie

Profile
• 76% average working interest in 211,000 acres

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

6,800' to 10,300'.

• 77.0 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 62 gas wells.
• Recompleted 10 gas wells.
2004 Plans
• Drill up to 89 gas wells.
• Recomplete 12 gas wells.

DD NEBU/32-9 Units

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

San Juan Basin of northwestern New Mexico.
• Coalbed natural gas development began in the late

•

1980s and early 1990s.
Includes 185 coalbed gas wells, 141
conventional wells, gas and water gathering
systems and an automated production control system.

• Produces primarily coalbed gas from the

Fruitland Coal formation at 3,000'.

• 23.6 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Received downspacing approval on all acreage.
• Drilled and completed 20 infill coalbed gas wells.
• Recavitated 7 coal wells.
•
Installed 3 pumping units for water removal.
• Drilled and completed 22 conventional gas wells.
• Recompleted 3 conventional wells.
2004 Plans
• Drill up to 55 infill coalbed gas wells.
• Recavitate 5 to 10 coal wells.
• Drill 21 conventional gas wells.
• Recomplete 16 conventional wells.

Gulf Coast
Gulf Coast

Gulf Offshore - Shelf
Gulf Offshore - Shelf

A A Carthage/Bethany Area

A A Grays Area

Profile
• 85% average working interest in 140,000 acres

in east Texas.
•
Initial position obtained in 1999 merger.
• Produces from the Cotton Valley, Travis Peak
and Pettit formations at 5,700' to 9,600'.
Includes 974 producing wells.

•
• 89.9 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 38 wells.
• Recompleted 29 wells.
2004 Plans
• Complete 7 wells carried over from 2003.
• Drill 43 wells.
• Recomplete 50 wells.
• Acquire additional working interest in key areas.

BB Groesbeck Area

Profile
• 74% average working interest in 154,000 acres

in east central Texas.

• Added acreage in 2002 merger.
• Produces from the Cotton Valley, Travis Peak
and Bossier formations at 6,000' to 13,000'.
Includes 494 producing wells.

•
• 46.3 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 35 wells.
• Recompleted 26 wells.
2004 Plans
• Complete 5 wells carried over from 2003.
• Drill up to 50 wells.
• Recomplete 54 wells.

CC South Texas

Profile
• 66% average working interest in 660,000 acres.
•
• Key areas include Zapata, Agua Dulce/N. Brayton,

Initial position obtained in 1999 merger.

Houston and Pettus/Ray Ranch.

• Produces oil and gas from the Frio/Vicksburg,
Yegua, Wilcox and Woodbine trends at 1,500'
to 15,000'.

• 41.1 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 81 wells.
• Recompleted 74 wells.
• Acquired 3-D seismic.
2004 Plans
• Drill 71 wells.
• Recomplete 117 wells.

Profile
•

Includes 100% working interest in 1 well in
Galveston 424 and 65% working interest in 2 wells in
Galveston 389 and 424.
• Obtained in 2000 lease sale.
• Located offshore Texas in 100' of water.
2003 Activity
• Drilled Grays discovery well.
• Drilled 2 additional wells.
•
2004 Plans
• Complete construction and installation of

Initiated construction of production facilities.

production facilities and pipeline.
• Commence production from 3 wells.

BB Eugene Island 126 Area

Profile
•

Includes 12 blocks located in and around
Eugene Island 126.

• Working interests range from 25% to 100%.
• Obtained in 2003 merger.
• Located offshore Louisiana in 50' of water.
• Produces oil and gas from sands at 2,500' to 19,000'.
• 7.5 million barrels of oil equivalent reserves at 12/31/03.
2003 Activity
• Drilled and completed 4 wells at Eugene Island 126.
• Performed 7 well recompletion program in three fields:

Eugene Island 100, 108 and 126.

2004 Plans
• Drill 3 wells.

CC Main Pass 69 Field

Includes 5 blocks located in and around Main Pass 69.

Profile
•
• 100% working interest.
• Obtained in 2003 merger.
• Located offshore Louisiana in 50' of water.
• Produces oil and gas from sands at 3,000' to 12,000'.
• 10.9 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 3 wells at Main Pass 69.
• Reviewed seismic for potential exploration well.
2004 Plans
• Drill 1 exploration well at Main Pass 73.

Shelf Exploration Prospects

Profile
DD TIKAL
• Eugene Island 142, located offshore Louisiana in 45'

of water.

• Target formation: mid-Miocene sands at 17,000'

to 19,000'.

• 30% working interest.
• Deep shelf prospect.
• Net unrisked reserve potential: 3 million barrels

of oil equivalent.

• Apparent 2004 discovery.
EE MAMBA
• West Cameron 537, located offshore Louisiana in 175'

of water.

• Target formation: Miocene sands at 13,000'.
• 50% working interest.
• Net unrisked reserve potential: 7 million barrels

of oil equivalent.

FF TITAN
• Eugene Island 316, located offshore Louisiana in 230'

of water.

• Target formation: lower Pliocene/upper Miocene

sands at 15,500' to 16,000'.

• 100% working interest.
• Deep shelf prospect.
• Net unrisked reserve potential: 25 million barrels

of oil equivalent.

Finalize geophysical analysis and drilling contracts.

2004 Plans
•
• Bring in industry partners.
• Drill exploratory test wells.

BBCC

Gulf Offshore - Deepwater
Gulf Offshore - Deepwater

A A Nansen/Boomvang Complex

Includes 18 blocks in central East Breaks Area.

Profile
•
• 50% working interest at the Nansen facility.
• 20% working interest at the Boomvang facility.
• Obtained in 2003 merger.
• Located offshore Texas in 3,500' of water.
• Produces oil and gas from sands at 9,000' to 14,000'.
• Utilizes the world's first open-hull truss spars.
• 66.8 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled and completed 2 wells at Nansen.
•
Installed pipeline compressor at Nansen.
• Drilled and completed 4 wells at Boomvang.
Initiated installation of pipeline compressor
•
at Boomvang.

2004 Plans
•

Initiate production from 4 discovery wells drilled
in 2003 at Boomvang.

• Complete installation of pipeline compressor

at Boomvang.

BB Magnolia

GG Merganser/Vortex

BB Northeast British Columbia

Profile
• 25% working interest in Garden Banks 783 and 784.
• Obtained in 2003 merger.
• Located offshore Louisiana in 4,600' of water.
• Developing 1999 discovery.
• To produce oil and gas from sands at 12,000'

to 17,000'.

• 21.0 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled 6 wells.
• Completed hull construction in Korea and

transported to U.S. gulf coast.
• Continued construction of topside.
2004 Plans
•

Finish construction and installation of the tension-leg
platform.

• Commence production from 2 wells.

CC Red Hawk

Profile
• 50% working interest in Garden Banks 876, 877,

920 and 921.

• Obtained in 2003 merger.
• Located offshore Louisiana in 5,300' of water.
• Developing 2001 discovery.
• To produce gas from sands at 16,000' to 18,500'.
• Utilizing the world's first cell spar.
• 9.7 million barrels of oil equivalent reserves at 12/31/03.
2003 Activity
• Drilled and completed 2 wells.
• Continued construction of cell spar hull and topside.
2004 Plans
•
• Commence production from 2 gas wells.

Finish construction and installation of cell spar.

DD Cascade

Profile
• 25% working interest in Walker Ridge 206.
• Located offshore Louisiana in 8,200' of water.
• Lower Tertiary discovery well drilled in 2002.
2003 Activity
•
•
• Continued geophysical analysis.
2004 Plans
• Drill appraisal well.
• Continue evaluation of development options.

Finalized appraisal well location with partners.
Initiated study of development options.

Profile
• 50% working interest in Merganser, Atwater Valley

36 and 37.

• 33.3% working interest in Vortex, Atwater Valley

217 and 261.

• Obtained in 2003 merger.
• Located offshore Louisiana in 8,100' of water.
• Middle Miocene discovery wells drilled in 2001

at Merganser and 2002 at Vortex.

2003 Activity
• Studied development options.
•

Joined with partners in other nearby discoveries
to consider central hub.

2004 Plans
•
• Sanction project.

Finalize development plan.

HH Jack Prospect

Profile
• 25% working interest in Walker Ridge 759.
• Located offshore Louisiana in 7,100' of water.
• Target formation: lower Tertiary sands at 26,000'

to 28,000'.
2004 Plans
•
• Drill exploratory test well.

Finalize technical evaluation.

BB
CC
DDEE

EE St. Malo

Canada
Canada

Profile
• 22.5% working interest in Walker Ridge 678.
• Located offshore Louisiana in 6,900' of water.
2003 Activity
• Drilled discovery well in lower Tertiary formation.
2004 Plans
•
• Drill appraisal well.
•

Initiate study of development options.

Finalize appraisal well location.

FF Sturgis

Profile
• 25% working interest in Atwater Valley 182.
• Located offshore Louisiana in 3,700' of water.
2003 Activity
• Drilled discovery well in lower Miocene formation.
2004 Plans
•
• Drill appraisal well.

Finalize appraisal well location.

AA Mackenzie Delta/Beaufort Sea
Profile
• 48% average working interest in 3.1 million
exploratory acres in the Mackenzie Delta and
shallow waters of the Beaufort Sea.

• Devon is the largest holder of exploration acreage

in this area.

• Obtained in 2001 acquisition.
• Drilling limited to winter only.
• 2002 Tuk M-18 discovery estimated at 200-300

billion cubic feet gross.

2003 Activity
• Drilled 1 exploratory dry hole.
• Suspended drilling on 1 exploratory well due

to spring thaw.

2004 Plans
• Pursue farm-out opportunities on Beaufort Sea license.
• Monitor Mackenzie Valley pipeline developments.

Profile
• 74% average working interest in 2.3 million

acres in northwestern Alberta and northeastern
British Columbia.
Initial position obtained in 1998 merger.

•
• Key areas include Hamburg, Tooga/Peggo, Wildmint,

Tommy Lakes and Wargen.
• Primarily winter-only drilling.
• Produces oil and gas from multiple formations

including liquids-rich gas from the Slave Point at
8,000' to 10,000'.

• 75.7 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Completed 79 of 91 wells drilled, including:

27 wells at Ring Border.
6 wells at Chinchaga.
6 wells at Tommy Lakes.

• Significant Slave Point discoveries at Hamburg,

Chinchaga and Milligan.

2004 Plans
• Drill 98 total wells, including:

25 wells at Ring Border.
16 wells at Tooga/Peggo.
6 wells at Chinchaga.

CC Peace River Arch

Profile
• 70% average working interest in 1.3 million acres in

western Alberta.

• Added acreage in 2001 acquisition.
• Key areas include Dunvegan, Dreau, Eaglesham,

Pouce Coupe and Valhalla.

• Produces liquids-rich gas and light gravity oil from

multiple formations at 4,500' to 8,000'.

• 94.2 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Completed 76 of 86 wells drilled, including:

16 wells at Dunvegan.
12 wells at Progress.

2004 Plans
• Drill 120 total wells (84 gas, 36 oil), including:

34 gas wells at Dunvegan.
10 oil wells at Progress.

DD Deep Basin

Profile
• 48% average working interest in 1.6 million acres in

western Alberta.

• Operate 72% of company production.
• Obtained in 2001 acquisition.
• Key areas include Wapiti, Elmworth, Bilbo, Leland

and Hiding.

• Produces liquids-rich gas from primarily

Cretaceous formations at 3,000' to 13,500'.
• 79.1 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Completed 180 of 183 wells drilled, including:

61 wells at Elmworth.
35 wells at Wapiti.
32 wells at Bilbo.

• Expanded production facilities at Elmworth and Leland.
2004 Plans
• Drill 193 total wells, including:
66 wells at Elmworth.
53 wells at Wapiti.
21 wells at Bilbo.
12 wells at Leland.

• Continue production facilities expansion at Leland.

B e n e a t h t h e S u r f a c e

EE Foothills

Profile
• 53% average working interest in 1.2 million acres in

western Alberta and eastern British Columbia.
Initial position obtained in 1998 merger.

•
• Key exploratory areas include Grizzly Valley in

eastern British Columbia, Narraway, Cabin Creek
and Findley in west central Alberta and Bighorn
and Moose in southern Alberta.
• High impact, long-lived reserves.
• Produces gas from multiple formations at

4,000' to 15,000'.

• 85.4 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Completed 27 of 30 gas wells drilled, including:

7 wells at Findley.
5 wells at Lynx.
2 wells at Bighorn.

•

Increased Grizzly Valley production from 10 to 30
MMcfd as a result of pipeline expansion.
Installed additional compression at Narraway,
Findley and Lynx.

2004 Plans
• Drill 39 total wells, including:

20 wells st Narraway, Lynx and Findley.
10 wells at Grizzly Valley, Bighorn and Moose.

FF Thermal Heavy Oil

Profile
• 44% average working interest in 340,000 acres

in eastern Alberta oil sands.
•
Initial position obtained in 1998 merger.
• Key areas include Jackfish (100% interest),

Dover (92% interest) and Surmont (13% interest).

• Steam-Assisted Gravity Drainage (SAGD) is the

principle recovery method.

• 300 million barrel potential at Jackfish.
2003 Activity
• Launched $400 million Jackfish SAGD project.
• Requested regulatory approval for 35,000 barrel

per day Jackfish project.

• Drilled 153 stratigraphic wells at Dover, Jackfish

and Surmont.

• Surmont SAGD project launched.
2004 Plans
• Proceed with regulatory approval and engineering

design at Jackfish.

• Acquire additional acreage and seismic at Jackfish.

CC
DDDD

International
International

A A Azerbaijan - ACG

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

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 merger.

•
• Major oil export pipeline to be completed in 2005.
• Expect in excess of 50,000 barrels per day net to Devon

beginning in 2008 - 2009.

• 129.2 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Drilled 1 extended reach well from the

Chirag platform.

• Drilled remaining 6 wells for future production from the

Central Azeri platform.

2004 Plans
• Drill 1 extended reach well from the Chirag platform.
• Convert 2 wells to injector wells.
•
• Drill 8 to 10 wells for future production from the

Install Central Azeri platform and production facilities.

East Azeri and West Azeri platforms.
• Sanction phase 3 field development.

BB China - Panyu

Profile
• 24.5% working interest in 950,000 acres in block

15/34 offshore China.

• Located in the Pearl River Mouth Basin in 300' of water.
• Obtained in 2000 merger.
• Produces oil from 1998 and 1999 Panyu discoveries.
• 17.3 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Completed construction and installation of Panyu facilities.
• Completed construction and commissioned

floating production, storage and offloading vessel (FPSO).

• Drilled 6 development wells at Panyu.
• Commenced production.
2004 Plans
• Drill 21 development wells at Panyu.
• Drill 1 to 2 exploratory wells in satellite fields.

CC Equatorial Guinea - Zafiro

Profile
• 23.75% working interest in 35,900 acres in the

Zafiro field in block B offshore Equatorial Guinea.

• Obtained in 2003 merger.
•

Field facilities include one fixed production
platform and 2 floating production, storage and
offloading vessels (FPSO) in 500' to 2,500' of water.

• Contains 48 producing wells and 13 injector wells.
• Produces oil from a complex system of reservoir

channels at 5,000' to 6,000'.

• 107.9 million barrels of oil equivalent reserves

at 12/31/03.
2003 Activity
• Completed construction and commissioned

the Serpentina FPSO in Southern Expansion Area (SEA).
• Completed 11 producers and 1 injector well in the SEA.
• Drilled and completed 9 additional wells

elsewhere in the field.

• Commenced production from the SEA.
•

Increased gross field production to record
290,000 barrels per day.

2004 Plans
• Expect to reach cost recovery payout mid-year.
• Drill 18 to 20 wells.
• Evaluate 3-D seismic for future potential.

DD South Atlantic Margin Exploration

Profile
• 5.1 million net acres in 10 licensed blocks

offshore West Africa:

Block 10 offshore Angola; 35% interest.
Block 16 offshore Angola; 15% interest.
Block 24 offshore Angola; 65% interest.
Agali block offshore Gabon; 50% interest.
Keta block offshore Ghana; 50% interest.
Block B offshore E.G.; 23.75% interest.
Block C offshore E.G.; 37.6% interest.
Block N offshore E.G.; 34% interest.
Block P offshore E.G.; 38.4% interest.
Block 256 offshore Nigeria; 95% interest.

• 1.1 million net acres in 5 licensed blocks

offshore Brazil:

BC-2 block; 15% interest.
BM-BAR-3 block; 100% interest.
BM-C-8 block; 60% interest.
BM-C-15 block; 65% interest.
BM-S-22 block; 20% interest.
• Obtained positions 1999 - 2003.
2003 Activity
• Drilled 2 exploratory dry holes on blocks 16 and

24 in Angola.

• Acquired 3-D seismic on block 10 in Angola.
• Drilled 1 exploratory dry hole on the Keta block in Ghana.
• Secured farmout agreements with industry

partners on block C in E.G.

• Drilled 1 exploratory dry hole on block N in E.G.
• Acquired 3-D seismic on block P in E.G.
• Acquired 3-D seismic on block 256 in Nigeria.
• Acquired 3-D seismic on block BM-BAR-3 in Brazil.
• Solicited farmout on block BM-C-8 in Brazil.
2004 Plans
• Drill 1 exploratory well on block 24 in Angola.
• Drill 1 exploratory well on block 10 in Angola.
• Drill 1 exploratory well on block B in E.G.
• Drill 1 exploratory well on block C in E.G.
• Drill 1 exploratory well on block P in E.G.
• Drill 1 exploratory well on block 256 in Nigeria.
• Drill 1 exploratory well on block BM-C-8 in Brazil.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Financial Statements and Management’s
Discussion and Analysis

30 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
59 Independent Auditors’ Report
60 Consolidated Balance Sheets
61 Consolidated Statements of Operations
62 Consolidated Statements of Stockholders’ Equity

and Comprehensive Income (Loss)
63 Consolidated Statements of Cash Flows
64 Notes to Consolidated Financial Statements

Average Oil Price
Received
($ per Bbl)

Average Gas Price
Received
($ per Mcf)

Total Assets
($ Billions)

Stockholders’ Equity
($ Billions)

3
6
.
5
2

9
9
.
4
2

1
4
.
1
2

1
7
.
1
2

8
7
.
7
1

4
8
.
3 3
5
.
3

0
8
.
2

9
0
.
2

1
5
.
4

2
.
7
2

1
.
1
1

2
.
6
1

2
.
3
1

9
.
1 6
.
6

7
.
4

3
.
3

5
.
2

Devon’s average realized
oil prices increased 18%
in 2003...

...while our average
realized natural gas
prices increased 61%.

The Ocean merger and
record net earnings
pushed total assets to
$27.2 billion...

...and more than
doubled stockholders’
equity to $11.1 billion.

B e n e a t h t h e S u r f a c e

Selected 11-Year Financial Data (1)

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 costs and expenses
Depreciation, depletion and amortization of property

and equipment

Accretion of asset retirement obligation
Amortization of goodwill (2)
General and administrative expenses
Expenses related to mergers
Interest expense (3)
Dividends on subsidiary’s preferred stock
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 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

1993

1994

1995

1996

355
189
13
—
31

588

227
—

170
—
—
51
11
42
—
—
—
180
—
(68)

613

(25)
(55)
7
(62)

(1.27)
(1.27)

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

529
211
29
—
36

805

271
—

175
—
—
57
—
59
—
—
—
—
—
106

668

137
151
47
104

1.97
1.92

53
56

1,336

1,475

1,639

2,242

—
508
—
472
49

—
457
30
688
52

—
565
48
739
52

—
511
136
1,160
63

$
$
$
$
$

$
$

$
$
$
$
$
$
$
$
$
$
$
$

$
$
$
$

$
$

$
$
$
$

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

and Indonesian operations, Devon acquired new Egyptian and Indonesian assets in the April 2003 Ocean merger. Amounts and activities related to these new Egyptian
and Indonesian operations are included in Devon’s continuing operations in 2003.

(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

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

accounting principle of ($1), $49 and $16 million in 1993, 2001 and 2003, respectively, and the results of discontinued operations of ($29), $0, $9, $15,
$13, ($35), $39, $69, $31 and $45 million in 1993 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.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

1997

1998

1999

2000

2001

2002

2003

5-YEAR
GROWTH RATE

10-YEAR
GROWTH RATE

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

1,588
3,897
407
1,460
37

1,150

2,627

2,933

4,350

7,389

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)

1,282
1,174

1,793
36
—
307
7
502
2
(69)
(1)
111
—
514

1,178

827

1,343

1,966

2,910

4,291

5,658

(226)
(218)
12
(230)

(3.35)
(3.35)

69
75

(201)
(236)
—
(236)

(3.32)
(3.32)

71
77

(193)
(154)
4
(158)

(1.68)
(1.68)

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

1,731
1,747
10
1,737

8.32
8.07

209
217

1,965

1,931

6,096

6,860

13,184

16,225

27,162

—
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

677
7,903
4,370
11,056
236

46%
63%
75%
183%
11%

64%

41%
230%

53%
NM
NM
45%
(12%)
57%
NM
NM
NM
(21%)
NM
NM

47%

NM
NM
NM
NM

NM
NM

24%
23%

70%

NM
55%
NM
71%
27%

16%
35%
41%
NM
2%

29%

19%
NM

27%
NM
NM
20%
(4%)
28%
NM
NM
NM
(5%)
NM
NM

25%

NM
NM
4%
NM

NM
NM

16%
16%

35%

NM
32%
NM
37%
17%

B e n e a t h t h e S u r f a c e

Management’s Discussion and Analysis of
Financial Condition and Results of Operations

OVERVIEW

On April 25, 2003, Devon supplemented its property portfolio and improved its growth outlook when it merged with Ocean

Energy. Former Ocean shareholders received 74 million new Devon common shares in exchange for their Ocean shares. The
merger enhances our current production profile and provides outstanding prospects for growth. We have substantially integrated
the Devon and Ocean organizations and consolidated all our Houston area employees at our downtown Houston location.

2003 was a record-breaking year for Devon. We produced 228 million Boe, the highest annual production in our history. Our

marketing and midstream operations also contributed $286 million to operating margins. Total revenues for 2003 exceeded $7
billion, and led to record profits and operating cash flow. Devon delivered the highest net earnings, $1.7 billion, and earnings per
diluted share, $8.07, in its 15 years as a public company.

Cash flow from operations was $3.8 billion for the year. This allowed Devon to fully fund our $2.6 billion of capital

expenditures, retire over $500 million in long-term debt and add almost $1 billion to cash on hand. We are continuing to
accumulate cash with the intent to repay debt as it matures in 2004 and subsequent years.

The significant increase in revenues and earnings resulted from both production growth and higher commodity prices. We

increased production by 40 million Boe, or 21%, due both to the Ocean merger and the impact of Devon’s exploration and
development activities. On a pro forma basis, as if the merger had been completed on January 1, 2002, Devon increased
production from retained properties year-over-year by 5.5%. Average oil, gas and NGL prices increased 18%, 61% and 33%,
respectively from 2002 to 2003. Our current price outlook assumes that, over the next few years, oil prices will decline toward the
OPEC stated price range of $22 to $28 per barrel from more than $30 per barrel today. Our outlook is that natural gas prices will
remain in a range of $3 to $5 per MMBtu for the foreseeable future. Historically, the OPEC basket price has been approximately $2
per barrel less than the NYMEX price.

In addition to dramatically increasing production and revenues, the Ocean merger increased our expenses in most categories.

Furthermore, higher oil, gas and NGL prices have led to upward pressure on many of Devon’s expenses such as power and fuel.
Higher oil and gas prices have also led to higher demand for oilfield supplies and services and have often caused increases in the
costs of such goods and services. However, these same commodity price increases have also resulted in higher costs that are
opportunity-driven. For example, with the increase in oil, gas and NGL prices, more well workovers and repairs and maintenance
costs can be profitably performed to maintain or increase production volumes.

Additionally, the weakening of the U.S. dollar versus the Canadian dollar caused increases in all of our Canadian dollar

expenses as expressed in U.S. dollars. This contributed approximately $88 million in aggregate, or $0.39 per Boe, to 2003
production and operating costs, depreciation, depletion and amortization expenses and general and administrative expenses.
Based on Devon’s assumption that the average Canadian-to-U.S. dollar exchange rate will increase from $0.7160 in 2003 to
$0.7600 in 2004, the exchange rate effect would increase these expense categories another $58 million, or $0.23 per Boe, from
2003 to 2004.

Because oil, gas and NGL prices are influenced by many factors outside of our control, Devon’s management has focused its

efforts on increasing oil and gas reserves and production and controlling costs. Devon’s future earnings and cash flows are
dependent on our ability to continue to contain our overall cost structure at a level that will allow for profitable production.

Devon drilled almost 300 exploration wells and more than 1,900 development wells during 2003. We incurred finding and
development costs, including business combinations, of $7.9 billion in 2003. Including 556 million Boe of proved reserves that were
acquired, Devon replaced 321% of annual production. We closed 2003 with proved reserves of 2.1 billion Boe. This resulted in per-
unit finding and development costs, including business combinations, which were higher than both Devon’s historical and the
industry averages. Management is focused on lowering our per-unit finding and development costs in future years.

Timing differences often occur between the years in which capital costs are incurred and the years in which related proved

reserves are booked. This contributed significantly to higher per-unit finding and development costs in recent years. For example,
Devon had several potential discoveries in 2003 from our exploration program. We believe our deepwater Gulf of Mexico
discoveries at St. Malo and Sturgis and the 2002 Cascade and Tuk M-18 discoveries will contribute significantly to Devon’s proved
reserves. However, due to the long-term nature of these projects, additional testing and approval of development plans are needed
before we can record the potential reserves as proved. Therefore, we have not yet recorded any reserves related to these projects,
even though the costs of drilling the wells have already been included in our finding and development costs.

Another contributor to 2003 finding and development costs is related to the development of previously booked undeveloped

reserves. We invested about $900 million of capital in 2003 developing reserves previously classified as proved undeveloped. Many
of these reserves were associated with assets acquired in the Ocean merger and other recent acquisitions. This allowed us to
reduce our percentage of reserves classified as proved undeveloped from 31% following the Ocean merger to 24% at year-end.

We expect to begin recording proved reserves within the next 12 to 18 months from some of our recent discoveries. We also
expect to reduce the amount of costs incurred to develop proved undeveloped reserves. Therefore, we are optimistic that our per-
unit finding and development costs will decline to more competitive levels.

During 2003, Devon marked its 15th anniversary as a public company. While we have consistently increased production over

this 15-year period, volatility in oil, gas and NGL prices has resulted in considerable variability in earnings and cash flows. Prices for
oil, natural gas and NGLs are determined primarily by market conditions. Market conditions for these products have been, and will
continue to be, influenced by regional and worldwide economic activity, weather and other factors that are beyond Devon’s control.
Devon’s future earnings and cash flows will continue to depend on market conditions.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Like all oil and gas exploration and production companies, Devon faces the challenge of natural production decline. As initial

reservoir pressures are depleted, oil and gas production from a given well naturally decreases. Thus, an oil and gas exploration and
production company depletes part of its asset base with each unit of oil or gas it produces. Historically, Devon has been able to
overcome this natural decline by adding, through drilling and acquisitions, more reserves than it produces. Devon’s future growth
will depend on its ability to continue to add reserves in excess of production.

In summary, as we head into 2004 and beyond, we are poised to continue growing organically through both our long-term
investment in high-impact exploration projects and our lower-risk development of proved undeveloped reserves. In addition, we
expect to continue to strengthen our balance sheet through the accumulation of cash to meet future debt maturities.

RESULTS OF OPERATIONS

Revenues Changes in oil, gas and NGL production, prices and revenues from 2001 to 2003 are shown in the following

tables. (Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.)

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe) (1)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe) (1)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe) (1)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe) (1)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

2003

62
863
22
228

25.63
4.51
18.65
25.88

1,588
3,897
407
5,892

2003

31
589
17
146

27.64
4.50
17.31
26.02

861
2,652
289
3,802

$
$
$
$

TOTAL
YEAR ENDED DECEMBER 31,
2002

2002 vs 2001 (2)

2003 vs 2002 (2)

+48%
+13%
+11%
+21%

+18%
+61%
+33%
+47%

+75%
+83%
+48%
+78%

42
761
19
188

21.71
2.80
14.05
17.61

909
2,133
275
3,317

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

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

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

DOMESTIC
YEAR ENDED DECEMBER 31,
2002

2002 vs 2001 (2)

2003 vs 2002 (2)

+31%
+22%
+16%
+23%

+26%
+55%
+29%
+46%

+64%
+89%
+51%
+79%

24
482
14
118

21.99
2.91
13.37
17.87

524
1,403
192
2,119

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

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

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

2001

36
489
8
126

21.41
3.84
16.99
22.19

784
1,878
131
2,793

2001

26
376
6

22.36
4.17
17.15
23.80

586
1,571
103
2,260

B e n e a t h t h e S u r f a c e

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe) (1)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe) (1)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

PRODUCTION

Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, gas and NGLs (MMBoe) (1)

AVERAGE PRICES
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Oil, gas and NGLs (per Boe) (1)

REVENUES ($ in millions)

Oil
Gas
NGLs
Oil, gas and NGLs

2003

14
267
5
63

23.54
4.57
23.08
26.25

318
1,222
114
1,654

2003

17
7
—
19

23.64
3.47
21.45
23.45

409
23
4
436

$
$
$
$

CANADA
YEAR ENDED DECEMBER 31,
2002

2002 vs 2001 (2)

2003 vs 2002 (2)

-14%
-4%
-5%
-7%

+12%
+74%
+45%
+55%

-4%
+67%
+37%
+45%

16
279
5
68

21.00
2.62
15.93
16.96

331
730
83
1,144

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

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

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

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2002

2002 vs 2001 (2)

2003 vs 2002 (2)

+662%
NM
NM
+719%

—
NM
NM
-1%

+660%
NM
NM
+710%

2
—
—
2

23.70
—
—
23.70

54
—
—
54

—
NM
NM
—

+1%
NM
NM
+1%

+4%
NM
NM
+4%

2001

8
113
2
29

17.84
2.73
16.43
16.80

146
307
28
481

2001

2
—
—
2

23.42
—
—
23.42

52
—
—
52

(1) Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of natural gas and oil, which rate is not

necessarily indicative of the relationship of oil and gas prices. NGL volumes are converted to Boe on a one-to-one basis with oil. The respective prices of oil, gas and NGLs are affected by
market and other factors in addition to relative energy content.

(2) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
NM Not meaningful.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

The average prices shown in the preceding tables include the effect of Devon’s oil and gas price 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.

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

WITH HEDGES
2002

2003

2001

$
$
$
$

25.63
4.51
18.65
25.88

21.71
2.80
14.05
17.61

21.41
3.84
16.99
22.19

WITHOUT HEDGES
2002

2001

2003

27.67
4.79
18.65
27.48

22.63
2.70
14.05
17.36

21.79
3.89
16.99
22.48

Oil Revenues 2003 vs. 2002 Oil revenues increased $679 million in 2003. An increase in 2003 production of 20 million

barrels caused oil revenues to increase by $436 million. The April 2003 Ocean merger accounted for 25 million barrels of
increased production, partially offset by production lost from the 2002 property divestitures of 5 million barrels. Oil revenues
increased $243 million due to a $3.92 increase in the average price of oil.

2002 vs. 2001 Oil revenues increased $125 million in 2002. An increase in 2002 production of 6 million barrels caused oil

revenues to increase by $112 million. The 2001 Anderson acquisition and 2002 Mitchell merger accounted for 11 million barrels of
increased production. This was partially offset by the effect of the 2002 property divestitures, which reduced 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.

Gas Revenues 2003 vs. 2002 Gas revenues increased $1.8 billion in 2003. A $1.71 per Mcf increase in the average gas
price caused revenues to increase by $1.5 billion. An increase in 2003 production of 102 Bcf caused gas revenues to increase
by $287 million. The April 2003 Ocean merger and January 2002 Mitchell merger accounted for 113 Bcf and 11 Bcf of increased
production, respectively, partially offset by production lost from the 2002 property divestitures of 36 Bcf. The remaining
production increase was primarily related to new drilling and development in the Barnett Shale properties.

2002 vs. 2001 Gas revenues increased $255 million in 2002. An increase in production of 272 Bcf caused gas revenues to
increase by $1.0 billion. The Anderson acquisition and Mitchell merger accounted for 323 Bcf of increased production. This was
partially offset by the effect of the 2002 property divestitures, which reduced 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.

NGL Revenues 2003 vs. 2002 NGL revenues increased $132 million in 2003. A $4.60 per barrel increase in average NGL

prices caused revenues to increase by $100 million. An increase in 2003 production of 3 million barrels caused revenues to
increase $32 million. The April 2003 Ocean merger and January 2002 Mitchell merger each accounted for 1 million barrels of
increased production. This was partially offset by production lost from the 2002 property divestitures of 1 million barrels. The
remaining production increase was primarily related to new drilling and development in the Barnett Shale properties.

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 acquisition and Mitchell merger 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.

Marketing and Midstream Revenues 2003 vs. 2002 Marketing and midstream revenues increased $461 million in 2003.

Of this increase, approximately $439 million was the result of an increase in gas and NGL prices. An increase in third-party
processed NGL volumes caused the remaining increase in 2003 revenues. The increase in volumes was primarily related to new
drilling and development in the Barnett Shale properties and an additional 24 days of production in 2003 due to the timing of the
January 2002 Mitchell merger. This was partially offset by volumes lost as a result of processing plant dispositions.

2002 vs. 2001 Marketing and midstream revenues increased $928 million in 2002. The Mitchell merger included significant

marketing and midstream assets which accounted for substantially all of the increase in revenues.

B e n e a t h t h e S u r f a c e

Operating Costs and Expenses The details of the changes in operating costs and expenses between 2001 and

2003 are shown in the table below.

2003

2003 vs 2002 (2)

2002

2002 vs 2001(2)

2001

YEAR ENDED DECEMBER 31,

Operating Costs and Expenses ($ in millions):

Production and operating expenses:

Lease operating expenses
Transportation costs
Production taxes

Total production and operating expenses

Depreciation, depletion and amortization

of oil and gas properties

Accretion of asset retirement obligation
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 properties

Total

Operating Costs and Expenses per Boe:
Production and operating expenses:

Lease operating expenses
Transportation costs
Production taxes

Total production and operating expenses

Depreciation, depletion and amortization

of oil and gas properties

Accretion of asset retirement obligation
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 properties (1)

Total

871
207
204
1,282

1,668
36
—
2,986

1,174

125
307
7

111
4,710

3.82
0.91
0.90
5.63

7.33
0.16
—
13.12

5.15

0.55
1.35
0.03

0.49
20.69

+40%
+34%
+84%
+45%

+51%
NM
NM
+50%

+45%

+19%
+40%
NM

-83%
+25%

+16%
+11%
+53%
+20%

+25%
NM
NM
+24%

+20%

—
+16%
NM

-86%
+3%

621
154
111
886

1,106
—
—
1,992

808

105
219
—

651
3,775

3.30
0.82
0.59
4.71

5.88
—
—
10.59

4.29

0.55
1.16
—

3.45
20.04

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

+39%
NM
-100%
+33%

+1,619%

+176%
+92%
-100%

-34%
+41%

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

-7%
NM
-100%
-11%

+1,059%

+83%
+27%
-100%

-56%
-6%

467
83
116
666

793
—
34
1,493

38
114
1

979
2,672

3.71
0.66
0.92
5.29

6.30
—
0.27
11.86

0.37

0.30
0.91
0.01

7.78
21.23

Though per Boe amounts for these expense items may be helpful for profitability trend analysis, these expenses are not directly attributable to production volumes.
All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.

(1)
(2)
NM Not meaningful.

Oil, Gas and NGLs Production and Operating Expenses 2003 vs. 2002 Lease operating expenses increased $250
million in 2003. The April 2003 Ocean merger accounted for $168 million of the increase. Lease operating expenses on our
historical properties increased $105 million, due to an increase in well workover expenses and increased power, fuel,
casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate
resulted in a $37 million increase in costs. These increases were partially offset by a decrease of $60 million due to the 2002
property divestitures.

The increase in lease operating expenses per Boe is primarily related to greater well workover expenses and increased

power, fuel and repairs and maintenance costs. Changes in the Canadian-to-U.S. dollar exchange rate also contributed to the
increase. Because of higher oil, gas and NGL prices, more well workovers and repairs and maintenance costs are performed to
either maintain or improve production volumes. These higher prices also resulted in increased power and fuel costs.

Transportation costs represent those costs paid directly to third-party providers to transport oil, gas and NGL

production sold downstream from the wellhead. Devon’s transportation costs increased $53 million in 2003. The April 2003
Ocean merger accounted for $31 million of the increase and $7 million was related to changes in the Canadian-to-U.S.
dollar exchange rate. The remainder of the increase was due primarily to an increase in gas production.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Production taxes increased $93 million in 2003. The majority of Devon’s production taxes are assessed on our onshore
domestic properties. In the U.S., most of the production taxes are based on a fixed percentage of revenues. Therefore, the 79%
increase in domestic oil, gas and NGLs revenues was the primary cause of the production tax increase.

2002 vs. 2001 Lease operating expenses increased $154 million in 2002. The Anderson acquisition and Mitchell merger

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 acquisition and Mitchell merger. We also divested some higher cost properties in 2002.
Transportation costs increased $71 million in 2002 primarily due to an increase in gas production from the Anderson

acquisition and Mitchell merger.

As stated previously, most U.S. 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 the production tax decrease.

Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”) DD&A of oil and gas properties is

calculated as the percentage of total proved reserve volumes produced during the year, multiplied by the net capitalized
investment plus future development costs in those reserves (the “depletable base”). Generally, if reserve volumes are revised up
or down, then the DD&A rate per unit of production will change inversely. However, if the depletable base changes, then the
DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A,
as 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.

2003 vs. 2002 Oil and gas property related DD&A increased $562 million in 2003. An increase in the combined U.S.,
Canadian and international DD&A rate from $5.88 per BOE in 2002 to $7.33 per BOE in 2003 caused oil and gas property
related DD&A to increase by $331 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger,
higher finding and development costs and changes in the Canadian-to-U.S. dollar exchange rate. A 21% increase in 2003 oil,
gas and NGLs production caused DD&A to increase $231 million.

2002 vs. 2001 Oil and gas property related DD&A increased $313 million in 2002. A 50% increase in 2002 oil, gas and

NGLs production caused DD&A to increase $394 million. The effects of the production increase were partially offset by a
decrease in the combined U.S., Canadian and international DD&A rate from $6.30 per Boe in 2001 to $5.88 per Boe in 2002.
The drop in the DD&A rate was primarily due to reductions of carrying value of oil and gas properties recorded in the fourth
quarter of 2001 and the second quarter of 2002.

Accretion of Asset Retirement Obligation Effective January 1, 2003, Devon adopted Statement of Financial Accounting

Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. We are 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. The initial measurement of the asset retirement obligation is to
record a separate liability at its fair value with an offsetting asset retirement cost recorded as an increase to the related property
and equipment on the balance sheet. The asset retirement cost is depreciated using a systematic and rational method similar to
that used for the associated property and equipment.

Because the asset retirement obligation is recorded at its discounted present value, Devon now records accretion
expense to reflect the increase in the asset retirement obligation due to the passage of time. Devon recorded $36 million of such
accretion expense during 2003.

Marketing and Midstream Operating Costs and Expenses 2003 vs. 2002 Marketing and midstream operating costs
and expenses increased $366 million in 2003. Of this increase, approximately $347 million was the result of an increase in prices
paid for gas and NGLs. An increase in third-party processed NGL volumes caused the remaining increase in 2003 costs and
expenses. The increase in volumes was primarily related to new drilling and development in the Barnett Shale properties and an
additional 24 days of production in 2003 due to the timing of the January 2002 Mitchell merger. This was partially offset by
volumes lost as a result of processing plant dispositions.

2002 vs. 2001 Marketing and midstream operating costs and expenses increased $761 million in 2002. The Mitchell merger

included significant marketing and midstream assets which accounted for substantially all of the increase in revenues.

General and Administrative Expenses (“G&A”) Devon’s net G&A consists of three primary components. The largest of
these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other
G&A items. The gross amount of these expenses is partially reduced by two offsetting components. One is the amount of G&A
capitalized pursuant to the full cost method of accounting. The other is the amount of G&A reimbursed by working interest
owners of properties for which Devon serves as the operator. These reimbursements are received during both the drilling and
operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is
recorded as net G&A in the consolidated statements of operations. Net G&A includes expenses related to oil, gas and NGL
exploration and production activities, as well as marketing and midstream activities. See the following table for a summary of
G&A expenses by component.

B e n e a t h t h e S u r f a c e

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

Net G&A

2003

2003 vs 2002

2002

2002 vs 2001

2001

YEAR ENDED DECEMBER 31,

(IN MILLIONS)

524
(140)
(77)
307

+35%
+44%
+9%
+40%

387
(97)
(71)
219

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

248
(77)
(57)
114

2003 vs. 2002 Gross G&A increased $137 million. This increase was primarily related to increased activities resulting from
the April 2003 Ocean merger, which added $92 million of costs and increased compensation and benefit costs. Included in the
increase of compensation and benefit costs is $15 million related to the increase in the value of investments of deferred
compensation plans that increases the obligation due to the plan participants. The increase in deferred compensation costs was
partially offset by an $11 million increase in other income. Additionally, $14 million of the compensation and benefit costs related
to an increase in pension related costs.

The increase in capitalized G&A of $43 million was primarily related to the April 2003 Ocean merger. Reimbursed G&A

increased $6 million. The increase in reimbursed amounts also was primarily related to the Ocean merger, partially offset by a
decline in reimbursements related to 2002 property divestitures.

2002 vs. 2001 Gross G&A increased $139 million, primarily due to increased activities resulting from the Anderson acquisition
and Mitchell merger. Also included in 2002 gross G&A was $13 million related to the abandonment of certain office space assumed
in the Santa Fe Snyder merger. The increase in capitalized G&A of $20 million was primarily related to the Anderson acquisition and
Mitchell merger. The increase in reimbursed G&A of $14 million also was primarily related to the Anderson acquisition and Mitchell
merger. This was partially offset by a decline in reimbursements related to 2002 property divestitures.

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 and asset retirement obligations, 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 test is imposed separately by country. In calculating future net revenues,
current prices and costs are generally held constant indefinitely. The effect of hedges is included 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.

Under the purchase method of accounting for business combinations, acquired oil and gas properties are recorded at

estimated fair value as of the date of purchase. Devon estimates 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 from the ceiling calculation is not necessarily indicative of the fair value of the reserves.
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 2003, 2002 and 2001, Devon reduced the carrying value of its oil and gas properties by $68 million, $651 million and

$883 million, respectively, due to the full cost ceiling limitations. The after-tax effect of these reductions in 2003, 2002 and 2001
was $36 million, $371 million and $533 million, respectively. The following table summarizes these reductions by geographic area.

United States
Canada
International

Total

2003

YEAR ENDED DECEMBER 31,
2002

2001

GROSS

NET OF
TAXES

GROSS

NET OF
TAXES

GROSS

NET OF
TAXES

—
—
68
68

—
—
36
36

(IN MILLIONS)

—
651
—
651

—
371
—
371

449
434
—
883

281
252
—
533

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

The 2003 reduction in carrying value was related to properties in Egypt, Russia and Indonesia. The Egyptian reduction was

primarily due to poor results of a development well that was unsuccessful in the primary objective. Partially as a result of this
well, we revised our Egyptian proved reserves downward. The Russian reduction was primarily the result of additional capital
costs incurred as well as an increase in operating costs. The Indonesian reduction was primarily related to an increase in
operating costs and a reduction in proved reserves. As a result, Devon’s Egyptian, Russian and Indonesian costs to be
recovered exceeded the related ceiling value by $26 million, $9 million and $1 million, respectively. These after-tax amounts
resulted in pre-tax reductions of the carrying values of Devon’s Egyptian, Russian and Indonesian oil and gas properties of $45
million, $19 million and $4 million, respectively, in the fourth quarter of 2003.

Additionally, during 2003, Devon elected to discontinue certain exploratory activities in Ghana, on certain properties in
Brazil and on other smaller concessions. After meeting the drilling and capital commitments on these properties, we determined
that these properties did not meet our internal criteria to justify further investment. Accordingly, Devon recorded a $43 million
charge associated with the impairment of these properties. The after-tax effect of this reduction was $38 million.

The 2002 Canadian reduction was primarily the result of lower prices. 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 expected 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, 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 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, Devon elected to abandon operations in Thailand, Malaysia, Qatar and on certain properties in

Brazil. After meeting the drilling and capital commitments on these properties, we determined that 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.

Other Income (Expenses) The details of the changes in other income (expenses) between 2001 and 2003 are shown in

the table below.

Other income (expenses):

Interest expense:

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

Total interest expense

Dividends on subsidiary’s preferred stock
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Impairment of ChevronTexaco Corporation common stock
Other income
Total

A discussion of the significant other income (expense) items follows.

2003

2002

2001

(IN MILLIONS)

(531)
(3)
(1)
(12)
50
—
(5)
(502)
(2)
69
1
—
37
(397)

(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)

Interest Expense 2003 vs. 2002 Interest expense decreased $31 million in 2003. An increase in the average debt
balance outstanding from $8.3 billion in 2002 to $8.9 billion in 2003 caused interest expense to increase $32 million. The
increase in average debt outstanding was attributable primarily to the debt assumed in the April 2003 Ocean merger. The
average interest rate on outstanding debt was 6.0% in both periods. Other items included in interest expense that are not
related to the debt balance outstanding were $63 million lower in 2003. Of this decrease, $46 million related to capitalized
interest, $10 million related to lower net accretion and $8 million related to a loss on the early extinguishment of the 8.75%
senior notes in 2002. The increase in capitalized interest was primarily related to additional unproved properties acquired in the
Ocean merger and the nature of those properties. The Ocean properties included significant deepwater Gulf and international
exploratory properties and major development projects.

B e n e a t h t h e S u r f a c e

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

$3.0 billion in 2001 to $8.3 billion in 2002 caused $319 million of the increase. The increase in average debt outstanding was
attributable primarily to the long-term debt issued and assumed as a result of the Mitchell merger and Anderson acquisition.
The average interest rate on outstanding debt decreased from 6.6% in 2001 to 6.0% in 2002 due to favorable rates on
borrowings under Devon’s $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. 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 merger and Anderson
acquisition.

Effects of Changes in Foreign Currency Exchange Rates Devon’s Canadian subsidiary has certain fixed-rate senior
notes that are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar while
the notes are outstanding increase or decrease the expected amount of Canadian dollars eventually required to repay the notes.
In addition, Devon’s Canadian subsidiary has cash and other working capital amounts denominated in U.S. dollars that also
fluctuate in value with changes in the exchange rate. Such changes in the Canadian dollar equivalent balance of the debt and
working capital are required to be included in determining net earnings for the period in which the exchange rate changes. The
increase in the Canadian-to-U.S. dollar exchange rate from $0.6331 at December 31, 2002, to $0.7738 at December 31, 2003,
resulted in a $69 million gain. The increase in the Canadian-to-U.S. dollar exchange rate from $0.6279 at December 31, 2001, to
$0.6331 at December 31, 2002, resulted in a $1 million gain. The drop in the Canadian-to-U.S. dollar exchange rate from
$0.6419 at October 15, 2001, (when the debt was assumed) to $0.6279 at December 31, 2001, resulted in an $11 million loss.

Impairment of ChevronTexaco Corporation Common Stock in 2002 In the fourth quarter of 2002, Devon recorded a

$205 million other-than-temporary impairment of our investment in 7.1 million shares of ChevronTexaco common stock. 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. We also
assumed the debentures, which mature in August 2008, in the 1999 PennzEnergy acquisition.

At the closing date of the PennzEnergy acquisition, we initially recorded the ChevronTexaco common shares at their fair

value, 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 and
the length of time the stock price has been below original cost. Other factors are 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 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 represented a 25% decline since June 30, 2002, and a 30% decline from the original
valuation in August 1999. As a result of the decline in value during the fourth quarter of 2002, Devon determined that the decline
was 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.

During 2003, the share price of ChevronTexaco common stock has increased to $86.39 at December 31, 2003. As a result,

the market value of Devon’s investment in ChevronTexaco common stock increased $141 million from December 31, 2002, to
December 31, 2003. The changes in the value of the shares since December 31, 2002, net of applicable taxes, have been
recorded directly to stockholders’ equity. However, depending on the future performance of ChevronTexaco’s common stock,
Devon may be required to record additional noncash charges in future periods if the value of the stock declines, and we
determine that the declines are other than temporary.

Income Taxes 2003 vs. 2002 Devon’s 2003 effective financial tax rate attributable to continuing operations was an
expense of 23% compared to a benefit of 144% in 2002. The 2003 rate benefited from a statutory rate reduction enacted by the
Canadian government that will be phased in through 2007. This rate reduction resulted in a $218 million benefit being recorded
in 2003 related to the lower tax rates being applied to deferred tax liabilities outstanding as of December 31, 2002. Excluding
the effects of the 2003 Canadian rate reduction, the impairment of ChevronTexaco stock in 2002 and the reduction of carrying
value of oil and gas properties in 2003 and 2002, the effective financial tax expense rates were 33% and 23% in 2003 and 2002,
respectively. These rates in both years were lower than the statutory federal tax rate primarily due to the tax benefits of certain
foreign deductions.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

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.

Results of Discontinued Operations On April 18, 2002, Devon sold its Indonesian operations to PetroChina Company

Limited for total cash consideration of $250 million. On October 25, 2002, we sold our Argentine operations to Petroleo
Brasileiro S.A. for total cash consideration of $90 million. On January 27, 2003, we sold our Egyptian operations to IPR Transoil
Corporation for total cash consideration of $7 million.

As a result, Devon 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.
Subsequent to the sale of its Egyptian and Indonesian operations, Devon acquired new Egyptian and Indonesian assets in the
April 2003 Ocean merger. Amounts and activities related to these new Egyptian and Indonesian operations are included in
Devon’s continuing operations in 2003.

Following are the components of the net results of discontinued operations for the years 2002 and 2001.

Net gain on sale of discontinued operations
Earnings from discontinued operations before income taxes
Income tax expense
Net results of discontinued operations

YEAR ENDED DECEMBER 31,

2002

2001

(IN MILLIONS)

31
23
9
45

—
56
25
31

Cumulative Effect of Change in Accounting Principle Effective January 1, 2003, Devon adopted SFAS No. 143 and
recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net of deferred taxes of $10 million.
Effective January 1, 2001, Devon adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities,
and 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 Cash payments for capital expenditures were $2.6 billion in 2003. This total includes $2.5 billion for

the acquisition, drilling or development of oil and gas properties. These amounts compare to cash payments for capital
expenditures of $3.4 billion in 2002 and $5.2 billion in 2001. The 2002 amounts included $1.7 billion related to the January 2002
Mitchell merger and $1.6 billion for other acquisitions and the drilling or development of oil and gas properties. The 2001
amounts included $3.5 billion related to the October 2001 Anderson acquisition and $1.6 billion for other acquisitions and the
drilling or development of oil and gas properties.

The April 2003 Ocean merger did not affect cash paid for 2003 capital expenditures because the consideration given was

Devon common stock. This differs from the January 2002 Mitchell merger, in which the consideration given was both Devon
common stock and cash, and the October 2001 Anderson acquisition, in which the consideration given was cash. As a result,
the Mitchell merger and Anderson acquisition did have an impact on capital expenditures paid in cash.

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

Operating cash flow continued to be a primary source of capital and liquidity in 2003. Operating cash flow in 2003 was

$3.8 billion, compared to $1.8 billion in 2002 and $1.9 billion in 2001. The increase in operating cash flow in 2003 was primarily
caused by the increase in revenues, partially offset by increased expenses, as discussed earlier in this section.

B e n e a t h t h e S u r f a c e

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 out control and difficult to predict.

To mitigate some of the risk inherent in oil and natural gas prices, we have utilized price collars to set minimum and
maximum prices on a portion of our production. Additionally, we have entered into various financial price swap contracts and
fixed-price physical delivery contracts to fix the price to be received for a portion of future oil and natural gas production. The
table below provides the volumes associated with these various arrangements as of December 31, 2003.

Oil production (MMBbls)

2004
2005

Natural gas production (Bcf)

2004
2005

PRICE
COLLARS

PRICE SWAP
CONTRACTS

FIXED-PRICE PHYSICAL
DELIVERY CONTRACTS

TOTAL

28
18

437
35

23
8

3
3

—
—

16
14

51
26

456
52

In addition to the above quantities, Devon also has fixed-price physical delivery contracts, for the years 2006 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 annual 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 effects of changing prices on operating cash flow. The combination of price collars, price swaps and
fixed-price contracts currently in place represents approximately 65% of estimated 2004 oil production and 48% of estimated
2004 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 February 2004, Devon announced that its capital expenditure budget for the year 2004 was approximately $2.8 billion.

This capital budget, which includes capital for exploration and production, marketing and midstream and other corporate items,
represents the largest planned use of available operating cash flow. To a certain degree, the ultimate timing of these capital
expenditures is within Devon’s control. Therefore, if oil and natural gas prices decline to levels below its acceptable levels,
Devon could choose to defer a portion of these planned 2004 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 2004, Devon anticipates
that its operating cash flow will exceed its planned capital expenditures and other cash requirements for the year. Devon
currently intends to accumulate any excess cash to fund future years’ debt maturities. Additional alternatives could be
considered based upon the actual amount, if any, of such excess cash.

Credit Lines

Other sources of liquidity are Devon’s revolving lines of credit. We have $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.

The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until June 2,
2004 (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 2, 2004, at the end of the Tranche B Revolving Period, Devon may convert the then outstanding balance under the
Tranche B facility to a one-year term loan by paying the Agent a fee of 25 basis points. The applicable borrowing rate would be
at LIBOR plus 112.5 basis points. On December 31, 2003, there were no borrowings outstanding under the $725 million U.S.
Facility. The available capacity under the U.S. Facility as of December 31, 2003, net of outstanding letters of credit, was
approximately $586 million.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Devon may borrow funds under the $275 million Canadian Facility until June 2, 2004 (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, 2003, there were no borrowings under the $275 million Canadian facility. The available capacity under
the Canadian Facility as of December 31, 2003, net of outstanding letters of credit, was approximately $214 million.

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

Amounts borrowed under the Credit Facilities bear interest at various fixed rate options that Devon may elect for periods
up to six months. Such rates are generally less than the prime rate. We 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 in arrears. We intend to renew the Credit
Facilities in 2004.

Devon also has access to short-term credit under its commercial paper program. Total borrowings under the U.S. Facility
and the commercial paper program may not exceed $725 million. Commercial paper debt generally has a maturity of between
seven to 90 days, although it can have a maturity of up to 365 days. Devon had no commercial paper debt outstanding at
December 31, 2003.

Devon’s Credit Facilities contain only one material financial covenant. This covenant requires Devon to maintain a ratio of

total funded debt to total capitalization of no more than 65%. The credit agreements contain definitions of total funded debt and
total capitalization that include adjustments to the respective amounts reported in Devon’s consolidated financial statements. In
accordance with the agreements, total funded debt excludes the debentures that are exchangeable into shares of
ChevronTexaco common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost
ceiling property impairments or goodwill impairments. As of December 31, 2003, Devon was in compliance with this covenant.
Devon’s access to funds from its Credit Facilities is not restricted under any “material adverse condition” clauses. It is not

uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the
credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s
financial condition, operations, properties or prospects considered as a whole, the borrower’s ability to make timely debt
payments, or the enforceability of material terms of the credit agreement. While Devon’s Credit Facilities and its $3 billion term
loan credit facility include covenants that require Devon to report a condition or event having a material adverse effect on
Devon, the obligation of the banks to fund the Credit Facilities is not conditioned on the absence of a material adverse effect.

Ocean Debt

In connection with the Ocean merger, Devon assumed $1.8 billion of debt. A summary of this debt is as follows:

Revolving credit line
Note payable
Senior notes and senior subordinated notes:

7.875% due August 2003 (principal of $100 million)
7.625% due July 2005 (principal of $125 million)
4.375% due October 2007 (principal of $400 million)
8.375% due July 2008 (principal of $200 million)
7.250% due September 2011 (principal of $350 million)
8.250% due July 2018 (principal of $125 million)
7.500% due September 2027 (principal of $150 million)
Other

Less amount classified as current as of April 25, 2003
Long-term debt

FAIR VALUE OF
DEBT ASSUMED
AS OF APRIL 25, 2003

(IN MILLIONS)

160
50

102
139
410
208
406
147
169
6
1,797
361
1,436

B e n e a t h t h e S u r f a c e

Change of control provisions required the outstanding borrowings under the credit line and note payable to be fully paid
immediately. Additionally, Devon was required to extend purchase offers for certain senior notes and the senior subordinated
notes. As a result of these purchase offers, which expired on June 13, 2003, Devon paid $118 million for the aggregate principal
amount tendered. The purchase price for each offer was 101 percent of the principal amount of the notes tendered plus accrued
and unpaid interest to and including the purchase date. All notes that were not tendered remain outstanding except as
described below.

Included in the $118 million of debt retired pursuant to the purchase offer were $13 million of the 8.375% notes and $57

million of the 7.875% notes. The remaining $195 million of 8.375% notes were called and redeemed on July 1, 2003. Additionally,
the remaining $43 million of 7.875% senior notes were paid August 1, 2003, when they were due.

Debt Ratings

Devon receives debt ratings from the major ratings agencies in the United States. In determining Devon’s debt rating, the

agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term
production growth opportunities. 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 Devon 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.

Devon’s cost of borrowing under its Credit Facilities and on the $635 million borrowed under 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 term loan facility would increase from LIBOR plus 100 basis points to LIBOR
plus 125 basis points. A ratings downgrade could also adversely impact our ability to economically access future debt markets.

As of December 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, 2003, is provided in the following table.

Long-term debt
Drilling obligations
Firm transportation agreements
Operating leases:

Office and equipment leases
Spar leases
FPSO leases

Other

Total

PAYMENTS DUE BY YEAR

2004

2005

2006

2007

2008

(IN MILLIONS)

AFTER
2008

TOTAL

337
437
100

47
11
20
6
958

497
189
68

40
15
20
7
836

1,291
55
57

36
15
20
6
1,480

400
1
46

28
15
20
5
515

761
—
36

24
15
20
5
861

5,606
—
158

85
243
36
4
6,132

8,892
682
465

260
314
136
33
10,782

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. Devon has sufficient production to utilize the majority of these transmission services.

We assumed two offshore platform spar leases through the 2003 Ocean merger. The spars are being used in the

development of the Nansen and Boomvang fields in the Gulf of Mexico. The operating leases are for 20-year terms and contain
various options whereby Devon may purchase the lessors’ interests in the spars. Devon has guaranteed that the spars will have
residual values at the end of the operating leases equal to at least 10% of the fair value of the spars at the inception of the
leases. The total guaranteed value is $20 million in 2022. However, this amount may be reduced under the terms of the lease
agreements.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Devon also has two floating, production, storage and offloading (FPSO) facilities that are being leased under operating
lease arrangements. One FPSO is being used in the Panyu project offshore China, and the other is being used in the Zafiro field
offshore Equatorial Guinea. The China lease expires in September 2009 and the Equatorial Guinea lease expires in July 2011.

The above table does not include $200 million of letters of credit that have been issued by commercial banks on Devon’s

behalf which, if funded, would become borrowings under Devon’s revolving credit facility. Most of these letters of credit have
been granted by Devon’s financial institutions to support Devon’s international and Canadian drilling commitments. The $8.9
billion of long-term debt shown in the table excludes $1 million of net discounts and a $27 million fair value adjustment. Both of
these items are included in the December 31, 2003, book balance of the debt.

Pension Funding and Obligations

Devon’s pension expense is recognized on an accrual basis over employees’ approximate service periods. It is generally

calculated independent of funding decisions or requirements. Devon recognized expense for its defined benefit pension plans of
$35 million, $16 million and $7 million in 2003, 2002 and 2001, respectively. Devon estimates that its pension expense will
approximate $24 million in 2004.

As compared to the “projected benefit obligation,” Devon’s qualified and nonqualified defined benefit plans were

underfunded by $137 million and $179 million at December 31, 2003 and 2002, respectively. The decrease in the underfunded
amount during 2003 was primarily caused by gains on investments and cash contributions of $67 million made to the plans by
Devon, partially offset by increases in the benefit obligations. A detailed reconciliation of the 2003 activity is included in Note 13
to the accompanying consolidated financial statements. Of the $137 million underfunded status at the end of 2003, $91 million
is attributable to various nonqualified defined benefit plans which have no plan assets. However, Devon has established certain
trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2003, these trusts had investments with a
market value of $66 million. The value of these trusts is included in noncurrent other assets in the accompanying consolidated
balance sheets.

As compared to the “accumulated benefit obligation,” Devon’s qualified defined benefit plans were underfunded by $22

million at December 31, 2003. The accumulated benefit obligation differs from the projected benefit obligation in that the former
includes no assumption about future compensation levels. Devon’s current intentions are to fund this accumulated benefit
obligation deficit during 2004 and provide sufficient funding in subsequent years to ensure the accumulated benefit obligation
remains funded. The actual amount of contributions required during this period will depend on investment returns from the plan
assets and any changes in actuarial assumptions made during the same period.

The calculation of pension expense and pension liability requires the use of a number of assumptions. Changes in these

assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions.
Devon believes that the two most critical assumptions affecting pension expense and liabilities are the expected long-term rate
of return on plan assets and the assumed discount rate.

Devon assumed that its plan assets would generate a long-term weighted average rate of return of 8.25% and 8.27% at
December 31, 2003 and 2002, respectively. 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 allocation for
Devon’s plan assets is 50% U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between
growth and value; 15% international equity securities, equally allocated between growth and value; and 20% debt securities.

Devon believes that its long-term asset allocation on average will approximate the targeted allocation. Devon regularly reviews

its actual asset allocation and periodically rebalances the investments to the targeted allocation when considered appropriate.

Pension expense increases as the expected rate of return on plan assets decreases. A decrease in Devon’s long-term rate

of return assumption of 100 basis points (from 8.25% to 7.25%) would increase the expected 2004 pension expense by
approximately $4 million.

Devon discounted its future pension obligations using a weighted average rate of 6.23% at December 31, 2003, compared
to 6.72% at December 31, 2002. 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 6.23% to 5.98%) would increase Devon’s pension liability at December 31, 2003, by approximately $16
million, and increase its estimated 2004 pension expense by approximately $2 million.

At December 31, 2003, Devon had unrecognized actuarial losses of $119 million. These losses will be recognized as a
component of pension expense in future years. Devon estimates that approximately $7 million and $6 million of the unrecognized
actuarial losses will be included in pension expense in 2004 and 2005, respectively. The $7 million estimated to be recognized in
2004 is a component of the total estimated 2004 pension expense of $24 million referred to earlier in this discussion.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in

Devon’s defined benefit pension plans will impact future pension expense and liabilities. Devon cannot predict with certainty
what these factors will be in the future.

B e n e a t h t h e S u r f a c e

Other Cash Uses

Devon’s common stock dividends were $39 million, $31 million and $25 million in 2003, 2002 and 2001, respectively.

Devon also paid $10 million of preferred stock dividends in 2003, 2002 and 2001.

During 2001, we repurchased 3,754,000 shares of Devon common stock at an aggregate cost of $190 million or $50.71

per share. We also repurchased shares of common stock in 2001 under an odd-lot repurchase program. Pursuant to this
program, Devon purchased and retired 232,000 shares of its common stock for a total cost of $14 million, or $57.40 per share.

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 properties.

Devon’s discounted present value of its proved oil, natural gas and NGL reserves is a major component of the ceiling

calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based
on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil,
natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries.
Different reserve engineers may make different estimates of reserve quantities based on the same data. Certain of Devon’s reserve
estimates are prepared by outside consultants, while other reserve estimates are prepared by Devon’s engineers. See Note 18 of
the accompanying consolidated financial statements.

The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior
estimates to reflect updated information. In the past four years, Devon’s annual revisions to its reserve estimates have averaged
approximately 2% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be
necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could
result in a full cost property writedown. In addition to the impact of the estimates of proved reserves on the calculation of the
ceiling, estimates of proved reserves are also a significant component of the calculation of DD&A.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves,

and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment.
The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely.
Therefore, the future net revenues associated with the estimated proved reserves are not based on Devon’s assessment of future
prices or costs. They 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, we 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 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, not quantities of reserves. Therefore, such
writedowns should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Derivative Instruments Devon enters into oil and gas financial instruments to manage its exposure to oil and gas price

volatility. We have also entered into interest rate swaps to manage our exposures to interest rate volatility. The interest rate
swaps mitigate either the effects on interest expense for variable-rate debt instruments or the debt fair values for fixed-rate
debt. Devon is not involved in any speculative trading activities of derivatives. All derivatives are accounted for in accordance
with SFAS No. 133 and are recognized on the balance sheet at their fair value.

A substantial portion of Devon’s derivatives consists of contracts that hedge the price of future oil and natural gas
production. These derivative contracts are cash flow hedges that qualify for hedge accounting treatment under SFAS No. 133.
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 these
hedging instruments, net of tax, are recorded directly to stockholders’ equity until the hedged oil or natural gas quantities are
produced. To qualify for hedge accounting treatment, Devon designates its cash flow hedge instruments as such on the date the
derivative contract is entered into or the date of a business combination which includes cash flow hedge instruments.
Additionally, Devon 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. If Devon fails to meet the requirements for using hedge accounting treatment, the changes in fair value
of these hedging instruments would not be recorded directly to equity but in the consolidated results of operations.

The estimates of the fair values of Devon’s commodity derivative contracts require substantial judgment. For these
contracts, we obtain 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. The resulting
estimated future cash inflows or outflows over the lives of the hedge contracts are discounted using Devon’s current borrowing
rates under our revolving credit facilities. In addition, we estimate the option value of price floors and price caps using the

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

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. Fair values of Devon’s other derivative contracts require less
judgment to estimate and are primarily based on quotes from independent third parties such as counterparties or brokers.

Business Combinations Devon has grown substantially during recent years through acquisitions of other oil and natural gas

companies. Most of these acquisitions have been accounted for using the purchase method of accounting. 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. Goodwill is assessed for impairment at least annually.

There are various assumptions made by Devon in determining the fair values of an acquired company’s assets and liabilities.

The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas
properties acquired. To determine the fair values of these properties, Devon prepares estimates of oil, natural gas and NGL
reserves. These estimates are based on work performed by Devon’s engineers and that of outside consultants. The judgments
associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.

However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require

more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies current
price and cost information to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a
business combination must be based on Devon’s estimates of future oil, natural gas and NGL prices. Estimates of future prices are
based on our 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 analyses. Forecasts of future prices from independent third parties are noted when Devon makes its pricing estimates.
Devon estimates future prices to apply to the estimated reserve quantities acquired. We also estimate future operating and
development costs to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then
discounted using a rate determined appropriate at the time of the business combination based upon Devon’s cost of capital.

Devon also applies these same general principles in arriving at the fair value of unproved properties acquired in a business
combination. These unproved properties generally represent the value of probable and 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 we
consider 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. 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.

Except for the 2002 Mitchell merger, Devon’s mergers and acquisitions have involved other entities whose operations were

predominantly in the area of exploration, development and production activities related to oil and gas properties. However, in
addition to exploration, development and production activities, Mitchell’s business also included substantial marketing and
midstream activities. Therefore, a portion of the Mitchell purchase price was allocated to the fair value of its marketing and
midstream facilities and equipment. This consisted primarily of natural gas processing plants and natural gas pipeline systems.

The Mitchell midstream assets primarily served gas producing properties that were also acquired by Devon. As a result,

certain of the assumptions regarding future operations of the gas producing properties were also integral to the value of the
midstream assets. For example, future quantities of natural gas estimated to be processed by natural gas processing plants were
based on the same estimates used to value the proved and unproved gas producing properties. Future expected prices for
marketing and midstream product sales were also based on price cases consistent with those used to value the oil and gas
producing assets acquired from Mitchell. Based on historical costs and known trends and commitments, Devon also estimated
future operating and capital costs of the marketing and midstream assets to arrive at estimated future cash flows. These cash flows
were discounted at rates consistent with those used to discount future net cash flows from oil and gas producing assets to arrive at
Devon’s estimated fair value of the marketing and midstream facilities and equipment.

In addition to the valuation methods described above, Devon performs other quantitative analyses to support the indicated

value in any business combination. These analyses include information related to comparable companies, comparable transactions
and premiums paid.

In a comparable company analysis, Devon reviews the public stock market trading multiples for selected publicly traded
independent exploration and production companies. The selected companies have financial and operating characteristics, such as
market capitalization, location of proved reserves and the characterization of those reserves that Devon deems to be similar to
those of the party to the proposed business combination. These comparable company multiples are compared to the proposed
business combination company multiples for reasonableness.

B e n e a t h t h e S u r f a c e

In a comparable transactions analysis, Devon reviews certain acquisition multiples for selected independent exploration and
production company transactions and oil and gas asset packages announced recently. The comparable transaction multiples are
compared to the proposed business combination transaction multiples for reasonableness.

In a premiums paid analysis, Devon uses a sample of selected independent exploration and production company transactions
in addition to selected transactions of all publicly traded companies announced recently to review the premiums paid to the price of
the target one day, one week and one month prior to the announcement of the transaction. Devon uses this information to
determine the mean and median premiums paid and compares them to the proposed business combination premium for
reasonableness.

Valuation of Goodwill Goodwill and intangible assets with indefinite useful lives are 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.

Drilling and Mineral Rights In 2003, the Securities Exchange Commission (“SEC”) inquired of the Financial Accounting
Standards Board regarding the application of certain provisions of SFAS No. 141, Business Combinations, and SFAS No. 142,
Goodwill and Other Intangible Assets, to oil and gas companies. SFAS Nos. 141 and 142 became effective for transactions
subsequent to June 30, 2001. SFAS No. 141 requires that all business combinations initiated after June 30, 2001, be accounted for
using the purchase method and that acquired intangible assets be disaggregated and reported separately from goodwill.
Specifically, the SEC’s inquiry is based on whether costs of contract-based drilling and mineral use rights (“mineral rights”) should
be recorded and disclosed as intangible assets under the guidance in SFAS Nos. 141 and 142. The current practice for Devon and
the industry is to present oil and gas related assets, including mineral rights, as property and equipment (tangible assets) on the
balance sheet. Since June 30, 2001, Devon has entered into business combinations with Anderson, Mitchell and Ocean with an
aggregate accounting purchase price of $18.2 billion. The majority of the purchase price has been allocated to oil and gas property.
An Emerging Issues Task Force Working Group (“EITF”) has been created to research the accounting and disclosure treatment

of mineral rights for oil and gas companies. As a result, the EITF has added Issue No. 03-O, “Whether Mineral Rights are Tangible
or Intangible Assets,” and Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil
and Gas Companies.” Currently, Devon does not believe that generally accepted accounting principles require the classification of
mineral rights as intangible assets and continues to classify these assets as oil and gas properties. However, the decisions of the
EITF may affect how Devon classifies these assets in the future. If the EITF ultimately determines that SFAS Nos. 141 and 142
require oil and gas companies to classify mineral rights as separate intangible assets, the amounts included in oil and gas
properties on the balance sheet that would be reclassified are not expected to exceed the following amounts:

Intangible proved drilling and mineral rights, net of

accumulated DD&A

Intangible unproved drilling and mineral rights
Total intangible drilling and mineral rights

DECEMBER 31, 2003

DECEMBER 31, 2002

(IN MILLIONS)

$
$
$

7,156
2,678
9,834

3,057
1,777
4,834

Amounts to be reclassified would be impacted by the provisions of the EITF consensus. The ultimate reclassification amount
could be materially different than the amounts above. Numerous decisions that could be included in the consensus would impact
the composition and amortization of the intangible assets, if any.

Devon believes that cash flows and results of operations would not be affected. Such intangible assets would likely continue

to be depleted and assessed for impairment in accordance with Devon’s accounting policies as prescribed under the full cost
method of accounting for oil and gas properties. Further, Devon does not believe the classification of the mineral rights as
intangible assets would affect compliance with covenants under our debt agreements.

Impact of Recently Issued Accounting Standards Not Yet Adopted In December 2003, the FASB issued FASB
Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (“FIN 46R”) which addresses how a
business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights
and accordingly should consolidate the entity. FIN 46R replaces FASB Interpretation No. 46, Consolidation of Variable Interest
Entities, which was issued in January 2003. Devon will be required to apply FIN 46R to variable interests in variable interest entities
(“VIEs”) created after December 31, 2003. For variable interests in VIEs created before January 1, 2004, FIN 46R will be applied
beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004,
the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts. Any difference
between the net amount added to the consolidated balance sheet and any previously recognized interest would be recognized as
the cumulative effect of a change in accounting principle. If determining the carrying amounts is not practicable, fair value at the
date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. Devon owns no
interests in variable interest entities; therefore, FIN 46R will not affect Devon’s consolidated financial statements.

SFAS Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was

issued in May 2003. SFAS No. 150 establishes standards for the classification and measurement of certain financial instruments

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

with characteristics of both liabilities and equity. SFAS No. 150 also includes required disclosures for financial instruments within its
scope. SFAS No. 150 was effective for instruments entered into or modified after May 31, 2003 and otherwise will be effective as of
January 1, 2004, except for mandatorily redeemable financial instruments. For certain mandatorily redeemable financial
instruments, SFAS No. 150 will be effective on January 1, 2005. The effective date has been deferred indefinitely for certain other
types of mandatorily redeemable financial instruments. Devon currently does not have any financial instruments that are within the
scope of SFAS No. 150.

2004 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, 2003, reserve reports and other data in Devon’s
possession or available from third parties. Devon cautions that its future oil, natural gas and NGL production, revenues and
expenses are subject to all of the risks and uncertainties normally incident to the exploration for and development, production
and sale of oil, gas and NGLs. These risks include, but are not limited to, price volatility, inflation or lack of availability of goods
and services, environmental risks, drilling risks, regulatory changes, the uncertainty inherent in estimating future oil and gas
production or reserves and other risks as outlined below.

Additionally, Devon cautions that its future marketing and midstream revenues and expenses are subject to all of the risks
and uncertainties normally incident to the marketing and midstream business. These risks include, but are not limited to, price
volatility, environmental risks, regulatory changes, the uncertainty inherent in estimating future processing volumes and pipeline
throughput, cost of goods and services and other risks as outlined below.

Also, the financial results of Devon’s foreign operations are subject to currency exchange rate risks. Additional risks are

discussed below in the context of line items most affected by such risks.

Specific Assumptions and Risks Related to Price and Production Estimates Prices for oil, natural gas and NGLs are

determined primarily by prevailing market conditions. Market conditions for these products are influenced by regional and
worldwide economic conditions, weather and other local market conditions. These factors are beyond Devon’s control and are
difficult to predict. In addition to volatility in general, Devon’s oil, gas and NGL prices may vary considerably due to differences
between regional markets, transportation availability and costs and demand for the various products derived from oil, natural
gas and NGLs. Substantially all of Devon’s revenues are attributable to sales, processing and transportation of these three
commodities. Consequently, Devon’s financial results and resources are highly influenced by price volatility.

Estimates for Devon’s future production of oil, natural gas and NGLs are based on the assumption that market demand
and prices for oil, gas and NGLs will continue at levels that allow for profitable production of these products. There can be no
assurance of such stability. Also, Devon’s international production of oil, natural gas and NGLs is governed by payout
agreements with the governments of the countries in which Devon operates. If the payout under these agreements is attained
earlier than projected, Devon’s net production and proved reserves in such areas could be reduced.

Estimates for Devon’s future processing and transport of oil, natural gas and NGLs are based on the assumption that
market demand and prices for oil, gas and NGLs will continue at levels that allow for profitable processing and transport of
these products. There can be no assurance of such stability.

The production, transportation, processing and marketing of oil, natural gas and NGLs are complex processes which are

subject to disruption due to transportation and processing availability, mechanical failure, human error and 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 2004 will be substantially similar to those of 2003, unless otherwise noted.

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 a projected average 2004 exchange rate of $0.7600 U.S. dollar to $1.00
Canadian. The actual 2004 exchange rate may vary materially from this estimate. Such variations could have a material effect on
the following estimates.

Though Devon has completed several major property acquisitions and dispositions in recent years, these transactions are

opportunity driven. Thus, the following forward-looking data excludes the financial and operating effects of potential property
acquisitions or divestitures during the year 2004.

GEOGRAPHIC REPORTING AREAS FOR 2004

The following estimates of production, average price differentials and capital expenditures are provided separately for each

of the following geographic areas:

• the United States onshore;
• the United States offshore, which encompasses all oil and gas properties in the Gulf of Mexico;
• Canada; and
• International, which encompasses all oil and gas properties that lie outside of the United States and Canada.

B e n e a t h t h e S u r f a c e

YEAR 2004 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 2004. On a combined basis, Devon estimates its 2004 oil, gas and NGL production will total between 256 and 261
MMBoe. Of this total, approximately 95% is estimated to be produced from reserves classified as “proved” at December 31, 2003.

Oil Production We expect oil production in 2004 to total between 78 and 80 MMBbls. Of this total, approximately 97% is

estimated to be produced from reserves classified as “proved” at December 31, 2003. The expected ranges of production by
area are as follows:

United States Onshore
United States Offshore
Canada
International

(MMBBLS)

15 to 15
18 to 19
14 to 14
31 to 32

Oil Prices – Fixed Through various price swaps, Devon has fixed the price it will receive in 2004 on a portion of its oil

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.

BBLS/DAY

PRICE/BBL

MONTHS
OF PRODUCTION

United States Onshore
United States Offshore
Canada
International

11,000
18,000
15,000
20,000

$ 27.51
$ 27.16
$ 27.53
$ 26.03

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

Oil Prices – Floating Devon’s 2004 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 Onshore
United States Offshore
Canada
International

EXPECTED RANGE OF OIL PRICES
LESS THAN NYMEX PRICE

($3.00) to ($2.00)
($4.50) to ($2.50)
($6.50) to ($4.50)
($5.50) to ($3.00)

We have also entered into costless price collars that set a floor and ceiling price for a portion of our 2004 oil production

that is otherwise subject to floating prices. The floor and ceiling prices related to domestic and Canadian oil production are
based on the NYMEX price. The floor and ceiling prices related to international oil production are based on the Brent price. If the
NYMEX or Brent 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 or Brent 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.
We have adjusted the international oil prices shown in the following table to a NYMEX-based price, using Devon’s

estimates of 2004 differentials between NYMEX and the Brent price upon which the collars are based.

To simplify presentation, we have aggregated costless collars as of December 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.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

AREA (RANGE OF FLOOR PRICES/
CEILING PRICES)

United States Onshore

($20.00 - $21.50 / $26.50 - $27.90)
($20.00 - $22.00 / $28.35 - $29.75)
($22.00 - $22.00 / $30.10 - $30.60)

United States Offshore

($20.00 - $22.00 / $27.55 - $29.75)
($22.00 - $22.00 / $30.00 - $31.40)

Canada

($20.00 - $21.50 / $26.50 - $27.70)
($20.00 - $22.00 / $28.00 - $29.20)
($22.00 - $22.00 / $29.80 - $32.35)

International

($22.31 - $22.31 / $30.11 - $31.51)
($22.31 - $22.31 / $31.56 - $32.81)

WEIGHTED AVERAGE
CEILING
PRICE PER
BBL

FLOOR
PRICE PER
BBL

MONTHS OF
PRODUCTION

BBLS/DAY

3,000
6,000
2,000

6,000
7,000

3,000
5,000
8,000

$ 20.83
$ 21.42
$ 22.00

$ 27.43
$ 29.25
$ 30.35

Jan – Dec
Jan – Dec
Jan – Dec

$ 21.42
$ 22.00

$ 28.75
$ 30.74

Jan – Dec
Jan – Dec

$ 20.50
$ 21.10
$ 22.00

$ 27.07
$ 28.69
$ 31.14

Jan – Dec
Jan – Dec
Jan – Dec

27,000
10,000

$ 22.31
$ 22.31

$ 30.82
$ 31.96

Jan – Dec
Jan – Dec

Gas Production We expect 2004 gas production to total between 936 Bcf and 948 Bcf. Of this total, approximately 93%
is estimated to be produced from reserves classified as “proved” at December 31, 2003. The expected ranges of production by
area are as follows:

United States Onshore
United States Offshore
Canada
International

(BCF)

489 to 494
148 to 150
292 to 297
7 to 7

Gas Prices – Fixed Through various price swaps and fixed-price physical delivery contracts, we have fixed the price we

will receive in 2004 on a portion of our 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 Onshore
Canada
Canada

MCF/DAY

PRICE/MCF

8,435
43,578
41,920

$ 3.10
$ 2.76
$ 2.79

MONTHS OF
PRODUCTION

Jan – Dec
Jan – Jun
Jul – Dec

Gas Prices – Floating For the natural gas production for which prices have not been fixed, Devon’s 2004 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
determined to be 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 Onshore
United States Offshore
Canada
International

($0.80) to ($0.30)
($0.25) to ($0.05)
($1.10) to ($0.60)
($3.00) to ($2.00)

We have also entered into costless price collars that set a floor and ceiling price for a portion of our 2004 natural gas
production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by the
floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such
settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at
prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices
of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.
We have adjusted the prices shown in the following table to a NYMEX-based price, using Devon’s estimates of 2004

B e n e a t h t h e S u r f a c e

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.

To simplify presentation, we have aggregated costless collars 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)

MMBTU/DAY

WEIGHTED AVERAGE
FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

MONTHS OF
PRODUCTION

United States Onshore

($3.32 - $4.22 / $4.97 - $6.37)
($3.32 - $4.47 / $6.47 - $7.35)
($3.32 - $4.00 / $7.45 - $7.85)
($3.50 - $4.07 / $8.02 - $8.86)
($4.00 - $4.15 / $7.00 - $7.00)
($4.02 - $4.03 / $6.98 - $6.99)

United States Offshore

($3.25 - $3.25 / $7.00 - $7.00)
($3.50 - $3.50 / $7.40 - $7.90)
($4.00 - $4.00 / $7.43 - $8.80)
($4.00 - $4.12 / $7.00 - $7.00)
($4.00 - $4.00 / $7.00 - $7.00)

Canada

($4.10 - $4.21 / $6.46 - $7.07)
($4.06 - $4.59 / $7.17 - $7.94)
($3.98 - $4.13 / $8.43 - $8.75)
($3.96 - $4.25 / $9.14 - $9.64)
($3.96 - $4.05 / $9.91 - $10.54)
($4.60 - $4.85 / $6.53 - $6.53)
($4.60 - $4.86 / $6.53 - $6.71)

110,000
215,000
45,000
100,000
40,000
50,000

10,000
50,000
130,000
60,000
50,000

60,000
140,000
60,000
70,000
25,000
90,000
70,000

$
$
$
$
$
$

$
$
$
$
$

$
$
$
$
$
$
$

3.77
4.10
3.54
3.61
4.06
4.03

3.25
3.50
4.00
4.07
4.00

4.18
4.29
4.04
4.06
4.02
4.75
4.73

$ 5.91
$ 6.87
$ 7.62
$ 8.37
$ 7.00
$ 6.99

$ 7.00
$ 7.74
$ 7.71
$ 7.00
$ 7.00

$ 6.76
$ 7.51
$ 8.63
$ 9.33
$ 10.37
$ 6.53
$ 6.61

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

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

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

In the April 2003 Ocean merger, Devon assumed an obligation under a forward sale contract to deliver contractual

quantities of 55,600 MMBtu per day in 2004. Under the terms of this forward sale, the purchaser is obligated to make additional
payments in the event the spot price exceeds $3.00 per MMBtu in 2004. The spot price is based on a relevant regional first-of-
the-month price index as published monthly by Inside FERC as determined by Devon. As part of the purchase price allocation,
Devon recorded deferred revenues related to this forward gas sale based on the $3.00 price. These deferred revenues will be
recognized during 2004. If the monthly spot prices exceed these prices, Devon will receive additional cash payments from the
purchaser, which will also be recorded as gas revenues. Therefore, if the monthly spot prices for 2004 exceed $3.00 per MMBtu,
Devon will recognize gas revenues on the related quantities at a floating market price but will receive actual cash payments
equal only to the difference between the floating market price and $3.00. If the monthly spot prices for 2004 are equal to or less
than $3.00 per MMBtu, Devon will recognize gas revenues on the related quantities at a fixed price of $3.00 and will receive no
cash consideration for the delivered quantities of gas.

NGL Production We expect our 2004 production of NGLs to total between 22 MMBbls and 23 MMBbls. Of this total,

95% is estimated to be produced from reserves classified as “proved” at December 31, 2003. The expected ranges of
production by area are as follows:

United States Onshore
United States Offshore
Canada

(MMBBLS)

16 to 17
1 to 1
5 to 5

Marketing and Midstream Revenues and Expenses Devon’s marketing and midstream revenues and expenses are
derived primarily from our natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in
response to several factors. The factors include, but are not limited to, changes in production from wells connected to the
pipelines and related processing plants, changes in the absolute and relative prices of natural gas and NGLs, provisions of the
contract arrangements and the amount of repair and workover activity required to maintain anticipated processing levels.

These factors, coupled with uncertainty of future natural gas and NGL prices, increase the uncertainty inherent in
estimating future marketing and midstream revenues and expenses. Given these uncertainties, we estimate that 2004 marketing
and midstream revenues will be between $1.07 billion and $1.14 billion, and marketing and midstream expenses will be between
$860 million and $910 million.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

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, we estimate that 2004 lease operating expenses will be between $1.05 billion and $1.12 billion

and transportation costs will be between $220 million and $230 million. We estimate that production taxes will be between 3.1%
and 3.6% 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 2004 oil and gas property DD&A rate will depend on various

factors. Most notable among such factors are the amount of proved reserves that will be added from drilling or acquisition
efforts in 2004 compared to the costs incurred for such efforts, and the revisions to Devon’s year-end 2003 reserve estimates
that, based on prior experience, are likely to be made during 2004.

Given these uncertainties, we expect oil and gas property related DD&A expense for 2004 to be between $2.2 billion and

$2.3 billion. Additionally, Devon expects its DD&A expense related to non-oil and gas property fixed assets to total between
$120 million and $130 million. Based on these DD&A amounts and the production estimates set forth earlier, Devon expects its
consolidated DD&A rate will be between $9.00 per Boe and $9.30 per Boe.

Accretion of Asset Retirement Obligation As a result of the requirements of Statement of Financial Accounting

Standards No. 143, Accounting for Asset Retirement Obligations, Devon expects its 2004 accretion of its asset retirement
obligation to be between $40 million and $45 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 our 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 2004 is
expected to be between $305 million and $325 million.

This estimate does not include the potential non-cash effect on G&A caused by changes in the value of investments of

deferred compensation plans. Positive returns from these investments increase Devon’s G&A, while negative returns decrease G&A.

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 and
asset retirement obligations (the “costs to be recovered”), may not exceed a calculated “full cost ceiling.” The ceiling limitation is
the discounted estimated after-tax future net revenues from oil and gas properties plus the cost of properties not subject to
amortization. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are
generally held constant indefinitely. The costs to be recovered are compared to the ceiling on a quarterly basis. If the costs to be
recovered exceed the ceiling, the excess is written off as an expense. An expense recorded in one period may not be reversed in
a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant

indefinitely, and requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and
natural gas prices have historically been cyclical and, on any particular day at the end of a quarter, can be either substantially
higher or lower than Devon’s long-term price forecast that is a barometer for true fair value. 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.

Because of the volatile nature of oil and gas prices, it is not possible to predict whether we will incur a full cost writedown in

future periods.

Interest Expense Future interest rates, debt outstanding and oil, natural gas and NGL prices have a significant effect on
Devon’s interest expense. Devon can only marginally influence the prices it will receive in 2004 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.
The interest expense in 2004 related to Devon’s fixed-rate debt, including net accretion of related discounts, will be
approximately $475 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of
Devon’s long-term debt. Devon’s floating rate debt is discussed in the following paragraphs.

B e n e a t h t h e S u r f a c e

Devon has a 5-year term loan facility due in 2006 that bears interest at floating rates. Devon also has various debt
instruments that have been converted to floating rate debt through the use of interest rate swaps. Devon’s floating rate debt is
as follows:

DEBT INSTRUMENT

5-year term loan facility due in 2006
4.375% senior notes due in 2007
10.25% bond due in 2005
8.05% senior notes due in 2004
2.75% notes due in 2006
7.625% senior notes due in 2005

FACE VALUE

(IN MILLIONS)

$ 635
$ 400
$ 236
$ 125
$ 500
$ 125

FLOATING RATE

LIBOR plus 100 basis points
LIBOR plus 40 basis points
LIBOR plus 711 basis points
LIBOR plus 336 basis points
LIBOR less 26.8 basis points
LIBOR plus 237 basis points

Based on Devon’s interest rate projections, interest expense on its floating rate debt, including net amortization of

premiums, is expected to total between $45 million and $55 million in 2004.

Devon’s interest expense totals have historically included payments of facility and agency fees, amortization of debt
issuance costs, the effect of interest rate swaps not accounted for as hedges and other miscellaneous items not related to the
debt balances outstanding. We expect between $15 million and $20 million of such items to be included in its 2004 interest
expense. Also, we expect to capitalize between $25 million and $30 million of interest during 2004.

Based on the information related to interest expense set forth herein and assuming no material changes in Devon’s levels of
indebtedness or prevailing interest rates, Devon expects its 2004 interest expense will be between $510 million and $520 million.

Effects of Changes in Foreign Currency Rates Devon’s Canadian subsidiary has $400 million of fixed-rate senior notes

which are denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar during
2004 will increase or decrease the Canadian dollar equivalent balance of this debt. Such changes in the Canadian dollar
equivalent balance of the debt are required to be included in determining net earnings for the period in which the exchange rate
changes. Because of the variability of the exchange rate, it is difficult to estimate the effect which will be recorded in 2004.
However, based on the December 31, 2003, Canadian-to-U.S. dollar exchange rate of $0.7738 and Devon’s forecast 2004 rate
of $0.7600, Devon expects to record an expense of approximately $7 million. The actual 2004 effect will depend on the
exchange rate as of December 31, 2004.

Other Revenues Devon’s other revenues in 2004 are expected to be between $30 million and $35 million.

Income Taxes Devon’s financial income tax rate in 2004 will vary materially depending on the actual amount of financial pre-tax

earnings. The tax rate for 2004 will be significantly affected by the proportional share of consolidated pre-tax earnings generated by
U.S., Canadian and International operations due to the different tax rates of each country. There are certain tax deductions and credits
that will have a fixed impact on 2004’s income tax expense regardless of the level of pre-tax earnings that are produced. Given the
uncertainty of its pre-tax earnings amount, Devon estimates that its consolidated financial income tax rate in 2004 will be between
25% and 45%. The current income tax rate is expected to be between 20% and 30%. The deferred income tax rate is expected to be
between 5% and 15%. Significant changes in estimated capital expenditures, production levels of oil, gas and NGLs, the prices of
such products, marketing and midstream revenues, or any of the various expense items could materially alter the effect of the
aforementioned tax deductions and credits on 2004’s financial income tax rates.

YEAR 2004 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, we do not “budget,” nor can we reasonably predict, the timing or size of such
possible acquisitions, if any.

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 our price expectations for future
production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2004 capital
expenditures. In addition, if the actual material or labor 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 2004 capital expenditures for drilling and development efforts, plus
related facilities, to total between $2.14 billion and $2.54 billion. These amounts include between $510 million and $550 million
for drilling and facilities costs related to reserves classified as proved as of year-end 2003. In addition, these amounts include
between $950 million and $1.2 billion for other low risk/reward projects and between $680 million and $760 million for new,
higher risk/reward projects. Low risk/reward projects include development drilling that does not offset currently productive units
and for which there is not a certainty of continued production from a known productive formation. Higher risk/reward projects
include exploratory drilling to find and produce oil or gas in previously untested fault blocks or new reservoirs.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

The following table shows expected drilling and facilities expenditures by geographic area.

UNITED STATES
ONSHORE

UNITED STATES
OFFSHORE

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

Total

$270 - $280
$405 - $560
$ 95 - $105
$770 - $945

$130 - $140
$ 95 - $110
$235 - $255
$460 - $505

CANADA
(IN MILLIONS)

$ 40 - $ 50
$400 - $500
$250 - $280
$690 - $830

INTERNATIONAL

TOTAL

$ 70 - $ 80
$ 50 - $ 60
$100 - $120
$220 - $260

$ 510 - $ 550
$ 950 - $1,230
$ 680 - $ 760
$2,140 - $2,540

In addition to the above expenditures for drilling and development, Devon expects to spend between $90 million to $100
million on its marketing and midstream assets, which include its oil pipelines, gas processing plants, CO2 removal facilities and
gas transport pipelines. Devon also expects to capitalize between $160 million and $170 million of G&A expenses in accordance
with the full cost method of accounting and to capitalize between $25 million and $30 million of interest. Devon also expects to
pay between $40 million and $45 million for plugging and abandonment charges and to spend between $90 million and $100
million for other non-oil and gas property fixed assets.

Other Cash Uses Devon’s management expects the policy of paying a quarterly common stock dividend to continue.

With the February 2004 increase in the quarterly dividend rate to $0.10 per share and 239 million shares of common stock
outstanding in January 2004, dividends are expected to approximate $96 million. Also, Devon has $150 million of 6.49%
cumulative preferred stock upon which it will pay $10 million of dividends in 2004.

Capital Resources and Liquidity Devon’s estimated 2004 cash uses, including its drilling and development activities, are

expected to be funded primarily through a combination of working capital and operating cash flow, with the remainder, if any,
funded with borrowings from Devon’s credit facilities. The amount of operating cash flow to be generated during 2004 is
uncertain due to the factors affecting revenues and expenses as previously cited. However, Devon expects its combined capital
resources to be more than adequate to fund its anticipated capital expenditures and other cash uses for 2004. As of December
31, 2003, Devon has $800 million available under its $1 billion of credit facilities, net of $200 million of outstanding letters of
credit. 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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information
about Devon’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes
in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The disclosures are not meant to be precise
indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information
provides indicators of how Devon views and manages its ongoing market risk exposures. All of Devon’s market risk sensitive
instruments were entered into for purposes other than speculative trading.

Commodity Price Risk Devon’s major market risk exposure is in the pricing applicable to its oil, gas and NGL production.

Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to its U.S.
and Canadian natural gas and NGL production. Pricing for oil, gas and NGL production has been volatile and unpredictable for
several years.

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

Devon’s total hedged positions on future production as of December 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 oil and natural gas

production in 2004 through 2005. The following tables include information on this fixed-price production by area. Where
necessary, the gas 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.

B e n e a t h t h e S u r f a c e

OIL PRODUCTION

AREA

United States Onshore
United States Offshore
Canada
International

AREA

United States Offshore
Canada
International

GAS PRODUCTION

AREA

United States Onshore

AREA

United States Onshore

2004

BBLS/DAY

PRICE/BBL

11,000
18,000
15,000
20,000

$ 27.51
$ 27.16
$ 27.53
$ 26.03

2005

BBLS/DAY

PRICE/BBL

10,000
6,000
6,000

$ 27.17
$ 27.26
$ 25.88

2004

MONTHS OF
PRODUCTION

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

MONTHS OF
PRODUCTION

Jan – Dec
Jan – Dec
Jan – Dec

MCF/DAY

PRICE/MCF

MONTHS OF
PRODUCTION

8,435

3.10

Jan – Dec

MCF/DAY

PRICE/MCF

MONTHS OF
PRODUCTION

2005

7,343

2.97

Jan – Dec

Costless Price Collars Devon has also entered into costless price collars that set a floor and ceiling price for a portion of
its 2004 and 2005 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. The floor and ceiling prices related to international oil production are
based on the Brent price. If the NYMEX or Brent 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 or Brent
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.

Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2004 and 2005 natural
gas production that otherwise is subject to floating prices. If the applicable monthly price indices are outside of the ranges set by
the floor and ceiling prices in the various collars, Devon and the counterparty to the collars will settle the difference. Any such
settlements will either increase or decrease Devon’s gas revenues for the period. Because Devon’s gas volumes are often sold at
prices that differ from the related regional indices, and due to differing Btu contents of gas produced, the floor and ceiling prices
of the various collars do not reflect actual limits of Devon’s realized prices for the production volumes related to the collars.

To simplify presentation, Devon’s costless collars as of December 31, 2003, have been aggregated in the following tables
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 international oil prices shown in the following tables have been adjusted to a NYMEX-based price, using Devon’s

estimates of future differentials between NYMEX and the Brent price upon which the collars are based.

The natural gas prices shown in the following tables have been adjusted to a NYMEX-based price, using Devon’s estimates

of future 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.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

OIL PRODUCTION

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

BBLS/DAY

United States Onshore

($20.00 - $21.50 / $26.50 - $27.90)
($20.00 - $22.00 / $28.35 - $29.75)
($22.00 - $22.00 / $30.10 - $30.60)

United States Offshore

($20.00 - $22.00 / $27.55 - $29.75)
($22.00 - $22.00 / $30.00 - $31.40)

Canada

($20.00 - $21.50 / $26.50 - $27.70)
($20.00 - $22.00 / $28.00 - $29.20)
($22.00 - $22.00 / $29.80 - $32.35)

International

($22.31 - $22.31 / $30.11 - $31.51)
($22.31 - $22.31 / $31.56 - $32.81)

2004
WEIGHTED AVERAGE

FLOOR
PRICE PER
BBL

CEILING
PRICE PER
BBL

MONTHS OF
PRODUCTION

$ 20.83
$ 21.42
$ 22.00

$ 27.43
$ 29.25
$ 30.35

Jan – Dec
Jan – Dec
Jan – Dec

$ 21.42
$ 22.00

$ 28.75
$ 30.74

Jan – Dec
Jan – Dec

$ 20.50
$ 21.10
$ 22.00

$ 27.07
$ 28.69
$ 31.14

Jan – Dec
Jan – Dec
Jan – Dec

3,000
6,000
2,000

6,000
7,000

3,000
5,000
8,000

27,000
10,000

$ 22.31
$ 22.31

$ 30.82
$ 31.96

Jan – Dec
Jan – Dec

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

BBLS/DAY

2005
WEIGHTED AVERAGE

FLOOR
PRICE PER
BBL

CEILING
PRICE PER
BBL

MONTHS OF
PRODUCTION

United States Onshore

($22.00 - $22.00 / $28.00 - $28.75)

United States Offshore

($22.00 - $22.00 / $27.50 - $29.00)

Canada

3,000

$ 22.00

$ 28.25

Jan – Dec

17,000

$ 22.00

$ 27.62

Jan – Dec

($22.00 - $22.00 / $27.50 - $29.10)

15,000

$ 22.00

$ 28.28

Jan – Dec

International

($22.75 - $22.75 / $28.45 - $29.25)

15,000

$ 22.75

$ 28.86

Jan – Dec

GAS PRODUCTION

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

MMBTU/DAY

2004
WEIGHTED AVERAGE

FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

MONTHS OF
PRODUCTION

United States Onshore

($3.32 - $4.22 / $4.97 - $6.37)
($3.32 - $4.47 / $6.47 - $7.35)
($3.32 - $4.00 / $7.45 - $7.85)
($3.50 - $4.07 / $8.02 - $8.86)
($4.00 - $4.15 / $7.00 - $7.00)
($4.02 - $4.03 / $6.98 - $6.99)

United States Offshore

($3.25 - $3.25 / $7.00 - $7.00)
($3.50 - $3.50 / $7.40 - $7.90)
($4.00 - $4.00 / $7.43 - $8.80)
($4.00 - $4.12 / $7.00 - $7.00)
($4.00 - $4.00 / $7.00 - $7.00)

Canada

110,000
215,000
45,000
100,000
40,000
50,000

10,000
50,000
130,000
60,000
50,000

60,000
140,000
60,000
70,000
25,000
90,000
70,000

$
$
$
$
$
$

$
$
$
$
$

$
$
$
$
$
$
$

3.77
4.10
3.54
3.61
4.06
4.03

3.25
3.50
4.00
4.07
4.00

4.18
4.29
4.04
4.06
4.02
4.75
4.73

$
$
$
$
$
$

$
$
$
$
$

5.91
6.87
7.62
8.37
7.00
6.99

7.00
7.74
7.71
7.00
7.00

6.76
$
7.51
$
8.63
$
$
9.33
$ 10.37
6.53
$
6.61
$

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

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

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

B e n e a t h t h e S u r f a c e

AREA (RANGE OF FLOOR PRICES/CEILING PRICES)

MMBTU/DAY

2005
WEIGHTED AVERAGE

FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

MONTHS OF
PRODUCTION

United States Onshore

($3.97 - $4.05 / $6.94 - $6.99)

United States Offshore

($3.50 - $3.50 / $7.50 - $7.50)
($4.04 - $4.17 / $7.00 - $7.00)

40,000

4.01

6.97

Jan – Jun

40,000
70,000

$
$

3.50
4.09

$
$

7.50
7.00

Jan – Dec
Jan – Jun

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 December 31, 2003, a 10% increase in the underlying
commodities prices would have increased the net liabilities recorded for Devon’s commodity hedging instruments by $253 million.

Fixed-Price Physical Delivery Contracts In addition to the commodity hedging instruments described above, Devon also

manages its exposure to oil and gas price risks by periodically entering into fixed-price contracts.

Devon has fixed-price physical delivery contracts for the years 2004 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, 2003, Devon had debt outstanding of $8.9 billion. Of this amount, $6.9 billion, or
77%, bears interest at fixed rates averaging 7.0%. Devon also has a floating-to-fixed interest rate swap in which Devon will
record a fixed rate of 6.4% on a notional amount of $97 million in 2003 through 2006 and 6.3% on a notional amount of $30
million in 2007.

The remaining $2.0 billion of debt outstanding bears interest at floating rates. Included in the floating-rate debt is debt with

floating rates and fixed-rate debt, which has been converted to floating-rate debt through interest rate swaps. The terms of
Devon’s various floating-rate debt facilities (revolving credit facilities and term-loan credit facility) allow interest rates to be fixed
at Devon’s option for periods of between seven to 180 days. A 10% increase in short-term interest rates on the floating-rate
debt facilities outstanding as of December 31, 2003, would equal approximately 22 basis points. Such an increase in interest
rates would increase Devon’s 2004 interest expense by approximately $1 million assuming borrowed amounts remain
outstanding for all of 2004. Following is a table summarizing the fixed-to-floating interest rate swaps with the related debt
instrument and notional amounts.

DEBT INSTRUMENT

NOTIONAL AMOUNT

FLOATING RATE

4.375% senior notes due in 2007
10.25% bond due in 2005
8.05% senior notes due in 2004
2.75% notes due in 2006
7.625% senior notes due in 2005

(IN MILLIONS)

$
$
$
$
$

400
235
125
500
125

LIBOR plus 40 basis points
LIBOR plus 711 basis points
LIBOR plus 336 basis points
LIBOR less 26.8 basis points
LIBOR plus 237 basis points

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 December 31, 2003, a 10% increase in the underlying interest rates would
have decreased the fair value of Devon’s interest rate swaps by $8 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.

Devon’s Canadian subsidiary, Devon Canada, has $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
10% decrease in the Canadian-to-U.S. dollar exchange rate would cause Devon to record a charge of approximately $40 million
in 2004. 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.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Management’s Responsibility
for Financial Statements

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 auditing 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 and Stockholders
Devon Energy Corporation:

We have audited the accompanying consolidated

balance sheets of Devon Energy Corporation and subsidiaries
as of December 31, 2003, and 2002 and the related
consolidated statements of operations, stockholders’ equity
and comprehensive income (loss) and cash flows for each of
the years in the three-year period ended December 31, 2003.
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.

The board of directors pursues its responsibilities for

In our opinion, the consolidated financial statements

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 & CEO

John Richels
President

Brian J. Jennings
Senior Vice President & CFO

Duke R. Ligon
Senior Vice President

Marian J. Moon
Senior Vice President

Darryl G. Smette
Senior Vice President

referred to above present fairly, in all material respects, the
financial position of Devon Energy Corporation and
subsidiaries as of December 31, 2003, and 2002, and the
results of their operations and their cash flows for each of the
years in the three year period ended December 31, 2003, 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; 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; effective
January 1, 2002, adopted the remaining provisions of SFAS
No. 142; and effective January 1, 2003, adopted SFAS No.
143, Asset Retirement Obligations.

Oklahoma City, Oklahoma
February 4, 2004

B e n e a t h t h e S u r f a c e

Consolidated Balance Sheets

DEVON ENERGY CORPORATION AND SUBSIDIARIES

DECEMBER 31, (IN MILLIONS, EXCEPT SHARE DATA)

2003

2002

Assets
Current assets:

Cash and cash equivalents
Accounts receivable
Inventories
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 ($3,336 and $2,289 excluded from amortization

in 2003 and 2002, respectively)

Less accumulated depreciation, depletion and amortization

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

Total assets

Liabilities and Stockholders’ Equity
Current liabilities:

Accounts payable:

Trade
Revenues and royalties due to others

Income taxes payable
Current portion of long-term debt
Deferred revenue
Accrued interest payable
Merger related expenses payable
Fair value of financial instruments
Current portion of asset retirement obligation
Accrued expenses and other current liabilities

Total current liabilities

Other liabilities
Asset retirement obligation, long-term
Debentures exchangeable into shares of

ChevronTexaco Corporation common stock

Other long-term debt
Preferred stock of a subsidiary
Fair value of financial instruments
Deferred income taxes

Stockholders’ equity:

Preferred stock of $1.00 par value. Authorized 4,500,000 shares;
issued 1,500,000 ($150 million aggregate liquidation value)
Common stock of $.10 par value Authorized 800,000,000 shares;

issued 239,767,000 in 2003 and 160,461,000 in 2002

Additional paid-in capital
Retained earnings (accumulated deficit)
Accumulated other comprehensive income (loss)
Deferred compensation and other
Treasury stock, at cost: 3,677,000 shares in 2003 and 3,704,000 shares in 2002

Total stockholders’ equity

Commitments and contingencies (Note 14)

Total liabilities and stockholders’ equity

See accompanying notes to consolidated financial statements

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

1,273
946
72
13
11
—
49
2,364

28,546
10,212
18,334
613
14
5,477
360
27,162

859
315
15
338
56
130
21
153
42
142
2,071
349
629

677
7,903
55
52
4,370

24
9,066
1,614
569
(32)
(186)
11,056

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

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

27,162

16,225

Consolidated Statements of Operations

DEVON ENERGY CORPORATION AND SUBSIDIARIES

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

2003

2002

2001

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
Accretion of asset retirement obligation
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
Dividends on subsidiary’s preferred stock
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 of tax
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 of tax
Net earnings

Diluted net earnings per share:

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

Weighted average common shares outstanding:

Basic
Diluted

See accompanying notes to consolidated financial statements

1,588
3,897
407
1,460
7,352

871
207
204
1,174
1,793
36
—
307
7
111
4,710
2,642

(502)
(2)
69
1
—
37
(397)

2,245

193
321
514

1,731

—
—
—

1,731
16
1,747
10
1,737

8.24
—
0.08
8.32

8.00
—
0.07
8.07

209
217

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)

48
(43)
5

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

B e n e a t h t h e S u r f a c e

DEVON ENERGY CORPORATION AND SUBSIDIARIES
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss)

(IN MILLIONS)

Balance as of December 31, 2000

Comprehensive income:

Net earnings
Other comprehensive income (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 income

Comprehensive income

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 income (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

Comprehensive income:

Net earnings
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments
Reclassification adjustment for derivative

losses reclassified into oil and gas sales
Change in fair value of financial instruments
Minimum pension liability adjustment
Unrealized gain on marketable securities

Other comprehensive income

Comprehensive income

Stock issued
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
Other

Balance as of December 31, 2003

See accompanying notes to consolidated financial statements

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

PREFERRED COMMON PAID-IN
CAPITAL

STOCK

ADDITIONAL

ACCUMULATED
OTHER
COMPRE-
HENSIVE
(ACCUMULATED INCOME
(LOSS)

RETAINED
EARNINGS

DEFICIT)

DEFERRED
COMPEN-
SATION
AND OTHER

TOTAL
STOCK-

TREASURY HOLDERS’

STOCK

EQUITY

—

—
—
—
—

—
—
—
—
—
—

—

—
—
—
—
—

—

—
—
—
—

—
—
—
—
—
—
—

3,564

(215)

(85)

(1)

—

—
—
—
—

—
—
—
—
—
—

—

—
—
—
—
—

3
—
—
—
—

—

—
—
—
—

7
—
—
—
1
—
—

—

—
—
—
—

48
(14)
12
—
—
—

103

—

—
—
—
—

—
—
—
(25)
(10)
—

(107)

(37)

(20)
216
(17)
22

—
—
—
—
—
—

3,610

(147)

(28)

—

—
—
—
—
—

1,559
6
—
—
3

5,178

—

—
—
—
—

3,824
31
—
—
33
—
—

104

—

—
—
—
—
—

—
—
(31)
(10)
—

(84)

1,747

—

—
—
—
—

—
—
(39)
(10)
—
—
—

—

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

—
—
—
—
—

(267)

—

766

198
(236)
19
89

—
—
—
—
—
—
—

9,066

1,614

569

—

—
—
—
—

—
—
—
—
—
1

—

—
—
—
—
—

—
—
—
—
(3)

(3)

—

—
—
—
—

—
—
—
—
(34)
2
3

(32)

—

—
—
—
—

—
(190)
—
—
—
—

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)
1,564
6
(31)
(10)
—

(188)

4,653

—

—
—
—
—

2
—
—
—
—
—
—

1,747

766

198
(236)
19
89
836
2,583
3,833
31
(39)
(10)
—
2
3

(186)

11,056

Consolidated Statements of Cash Flows

DEVON ENERGY CORPORATION AND SUBSIDIARIES

YEAR ENDED DECEMBER 31, (IN MILLIONS)

2003

2002

2001

1,731

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 asset retirement obligation
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
Investments and other current assets

Increase (decrease) 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
Capital expenditures, including acquisitions of businesses
Discontinued operations (including net proceeds from sale

of $336 million in 2002)

Other

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
Dividends paid on common stock
Dividends paid on preferred stock
Increase in long-term other liabilities

Net cash (used in) provided by 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

1,793
—
36
19
(69)
(1)
111
—
—
7
321
(48)

(164)
(8)
(26)

42
62
39
(41)
(36)
3,768

179
(2,587)

—
(24)
(2,432)

597
(1,118)
155
—
(39)
(10)
1
(414)
59
981
292
1,273

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
(76)

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

B e n e a t h t h e S u r f a c e

Notes To Consolidated Financial Statements
DECEMBER 31, 2003, 2002 AND 2001

DEVON ENERGY CORPORATION AND SUBSIDIARIES

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.

Nature of Business and Principles of Consolidation

Devon is engaged primarily in oil and gas exploration, development and production and the acquisition of properties. Such

activities domestically are concentrated in four geographic areas:

• the Permian Basin within Texas and New Mexico;
• the Rocky Mountains area of the United States stretching from the Canadian border into northern New Mexico;
• the Mid-Continent area of the central and southern United States; and
• the Gulf Coast, which includes properties located primarily in the onshore south Texas and south Louisiana areas and

offshore in the Gulf of Mexico.

Devon’s Canadian activities are located primarily in the Western Canadian Sedimentary Basin, and Devon’s international

activities—outside of North America—are located primarily in Azerbaijan, China, Egypt and areas in West Africa, including
Equatorial Guinea, Gabon and Cote d’Ivoire.

Devon also has marketing and midstream operations which are 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.

The accounts of Devon’s wholly owned subsidiaries are included in the accompanying consolidated financial statements. All

significant intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Significant items subject to such estimates and assumptions include the carrying value of
oil and gas properties, goodwill impairment assessment, asset retirement obligations, deferred income taxes, valuation of
derivative instruments and obligations related to employee benefits. Actual amounts could differ from those estimates.

Property and Equipment

Devon follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs incidental to the

acquisition, exploration and development of oil and gas properties, including costs of undeveloped leasehold, dry holes and
leasehold equipment, are capitalized. Internal costs incurred that are directly identified with acquisition, exploration and
development activities undertaken by Devon for its own account, and which are not related to production, general corporate
overhead or similar activities, are also capitalized. Interest costs incurred and attributable to unproved oil and gas properties
under current evaluation and major development projects of oil and gas properties are also capitalized.

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 quarterly. Significant unproved properties
are assessed individually. Costs of insignificant unproved properties are transferred to amortizable costs over average holding
periods ranging from three years for onshore properties to seven years for offshore properties.

Net capitalized costs are limited to the estimated future net revenues, discounted at 10% per annum, from proved oil,
natural gas and natural gas liquids reserves plus the cost of properties not subject to amortization. Such limitations are imposed
separately on a country-by-country basis and are tested quarterly. Capitalized costs are depleted by an equivalent unit-of-
production method, converting gas to oil at the ratio of six thousand cubic feet of natural gas to one barrel of oil. Depletion is
calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures (based
on current costs) to be incurred in developing proved reserves, net of estimated salvage values. No gain or loss is recognized
upon disposal of oil and gas properties unless such disposal significantly alters the relationship between capitalized costs and
proved reserves in a particular country. All costs related to production activities, including workover costs incurred solely to
maintain or increase levels of production from an existing completion interval, are charged to expense as incurred.

Depreciation and amortization of other property and equipment, including marketing and midstream assets and leasehold

improvements, are provided using the straight-line method based on estimated useful lives from three to 39 years.

In 2003, the Securities Exchange Commission (“SEC”) inquired of the Financial Accounting Standards Board regarding the

application of certain provisions of SFAS No. 141, Business Combinations, (“SFAS No. 141”) and SFAS No. 142, Goodwill and
Other Intangible Assets, (“SFAS No. 142”) to oil and gas companies. SFAS Nos. 141 and 142 became effective for transactions
subsequent to June 30, 2001. SFAS No. 141 requires that all business combinations initiated after June 30, 2001, be accounted

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

for using the purchase method and that acquired intangible assets be disaggregated and reported separately from goodwill.
Specifically, the SEC’s inquiry is based on whether costs of contract-based drilling and mineral use rights (“mineral rights”) should
be recorded and disclosed as intangible assets under the guidance in SFAS Nos. 141 and 142. The current practice for Devon
and the industry is to present oil and gas related assets, including mineral rights, as property and equipment (tangible assets) on
the balance sheet. Since June 30, 2001, Devon has entered into business combinations with Anderson Exploration, Ltd., Mitchell
Energy & Development Corp., and Ocean Energy, Inc. with an aggregate accounting purchase price of $18.2 billion. The majority
of the purchase price has been allocated to oil and gas property.

An Emerging Issues Task Force Working Group (“EITF”) has been created to research the accounting and disclosure
treatment of mineral rights for oil and gas companies. As a result, the EITF has added Issue No. 03-O, “Whether Mineral Rights
are Tangible or Intangible Assets,” and Issue No. 03-S, “Application of FASB Statement No. 142, Goodwill and Other Intangible
Assets, to Oil and Gas Companies.” Currently, Devon does not believe that generally accepted accounting principles require the
classification of mineral rights as intangible assets and continues to classify these assets as oil and gas properties. However, the
decisions of the EITF may affect how Devon classifies these assets in the future. If the EITF ultimately determines that SFAS Nos.
141 and 142 require oil and gas companies to classify mineral rights as separate intangible assets, the amounts included in oil
and gas properties on the balance sheet that would be reclassified are not expected to exceed the following amounts:

Intangible proved drilling and mineral rights, net of

accumulated DD&A

Intangible unproved drilling and mineral rights
Total intangible drilling and mineral rights

DECEMBER 31, 2003

DECEMBER 31, 2002

(IN MILLIONS)

7,156
2,678
9,834

3,057
1,777
4,834

Amounts to be reclassified would be impacted by the provisions of the EITF consensus. The ultimate reclassification amount

could be materially different than the amounts above as numerous decisions that could be included in the consensus would
impact the composition and amortization of the intangible assets, if any.

Devon believes that cash flows and results of operations would not be affected since such intangible assets would likely
continue to be depleted and assessed for impairment in accordance with Devon’s accounting policies as prescribed under the full
cost method of accounting for oil and gas properties. Further, Devon does not believe the classification of the mineral rights as
intangible assets would affect compliance with covenants under its debt agreements.

Effective January 1, 2003, Devon adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for

Asset Retirement Obligations (“SFAS No. 143”) 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. The initial measurement of the asset retirement obligation is to record a separate liability at its fair value with an
offsetting asset retirement cost recorded as an increase to the related property and equipment on the consolidated balance sheet.
The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property
and equipment.

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, Devon recorded a cumulative-effect-type adjustment for an increase to net earnings of $16 million net
of deferred taxes of $10 million. Additionally, Devon established an asset retirement obligation of $453 million, an increase to
property and equipment of $400 million and a decrease in accumulated DD&A of $79 million.

B e n e a t h t h e S u r f a c e

Following is a reconciliation of reported net income and the related earnings per share amounts assuming the provisions of

SFAS No. 143 had been adopted as of January 1, 2001.

Net earnings applicable to common stockholders, as reported
Less cumulative effect of change in accounting principle
Net change in depreciation, depletion and amortization of

property and equipment due to adoption of SFAS No. 143

Less accretion of asset retirement obligation
Deferred taxes

Effect on net earnings

Net earnings applicable to common stockholders, as adjusted

Basic earnings per share:

Net earnings applicable to common stockholders, as reported
Effect on net earnings
Net earnings applicable to common stockholders, as adjusted

Diluted earnings per share:

Net earnings applicable to common stockholders, as reported
Effect on net earnings
Net earnings applicable to common stockholders, as adjusted

YEAR ENDED DECEMBER 31,

2003

2002

2001

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

1,737
(16)

—
—
—

(16)

1,721

8.32
(0.08)
8.24

8.07
(0.07)
8.00

94
—

16
(25)
4

(5)

0.61
(0.03)
0.58

93
—

30
(15)
(6)

102

0.73
0.07
0.80

0.72
0.07
0.79

Following is a summary of the asset retirement obligation, assuming the provisions of SFAS No. 143 had been adopted as of

January 1, 2001.

Asset retirement obligation as of:

January 1, 2001
December 31, 2001
December 31, 2002

(IN MILLIONS)

$
$
$

244
397
453

Marketable Securities and Other Investments

Devon reports investments in debt and equity and other short-term securities at fair value, except for debt securities in
which management has the ability and intent to hold until maturity. Devon’s only significant investment security is the investment
in approximately 7.1 million shares of ChevronTexaco Corporation (“ChevronTexaco”) common stock which is reported at fair
value. Except for unrealized losses that are determined to be “other than temporary,” the tax effected unrealized gain or loss on
the investment in ChevronTexaco common stock is recognized in other comprehensive income (loss) and reported as a separate
component of stockholders’ equity.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets
acquired. Effective July 1, 2001, Devon adopted the provisions of SFAS No. 141, Business Combinations, and certain provisions
of SFAS No. 142, Goodwill and Other Intangible Assets. Effective January 1, 2002, Devon adopted the remaining provisions of
SFAS No. 142. Goodwill and intangible assets with indefinite useful lives are not amortized but are instead tested for impairment
at least annually. As of January 1, 2002, Devon had unamortized goodwill in the amount of $2.2 billion, which was subject to the
transitional goodwill impairment assessment provisions of SFAS No. 142. During 2002, goodwill increased to $3.6 billion at
December 31, 2002, due primarily to the January 2002 Mitchell merger. As a result of the April 2003 Ocean merger and the effects
of changes in the Canadian-to-U.S. dollar foreign exchange rates, goodwill increased $1.5 billion and $0.4 billion, respectively, to
$5.5 billion at the end of 2003. Devon performed its transitional impairment assessment of goodwill as of January 1, 2002, and its
annual assessments of goodwill in the fourth quarter of 2003 and 2002. Based on these assessments, 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, 2001.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

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

YEAR ENDED DECEMBER 31,

2003

2002

2001

(IN MILLIONS, EXCEPT PER SHARE DATA)

1,737
—
1,737

8.32
—
8.32

8.07
—
8.07

94
—
94

0.61
—
0.61

93
34
127

0.73
0.26
0.99

0.72
0.26
0.98

Revenue Recognition and Gas Balancing

Oil, gas and NGL revenues are recognized when the products are sold. During the course of normal operations, Devon and

other joint interest owners of natural gas reservoirs will take more or less than their respective ownership share of the natural
gas volumes produced. These volumetric imbalances are monitored over the lives of the wells’ production capability. If an
imbalance exists at the time the wells’ reserves are depleted, settlements are made among the joint interest owners under a
variety of arrangements.

Devon follows the sales method of accounting for gas production imbalances. A liability is recorded when Devon’s excess
takes of natural gas volumes exceed its estimated remaining recoverable reserves. No receivables are recorded for those wells
where Devon has taken less than its ownership share of gas production.

Marketing and midstream revenues are recorded on the sales method at the time products are sold or services are
provided to third parties. Revenues and expenses attributable to Devon’s NGL purchase and processing contracts are reported
on a gross basis since Devon takes title to the products and has risks and rewards of ownership.

Major Purchasers

No purchaser accounted for over 10% of revenues in 2003 and 2002. In 2001, Enron Capital and Trade Resource

Corporation accounted for 16% 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.

Hedging Activities

Devon enters into oil and gas financial instruments to manage its exposure to oil and gas price volatility. Devon has also
entered into interest rate swaps to manage its exposure to interest rate volatility. The interest rate swaps mitigate either the effects
of interest rate fluctuations on interest expense for variable-rate debt instruments or the debt fair values for fixed-rate debt.

In accordance with the transition provisions of SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging
Activities, (“SFAS No. 133”) Devon recorded a net-of-tax cumulative-effect-type adjustment of $37 million loss in accumulated
other comprehensive income (loss) (“AOCI”) to recognize the fair value of all derivatives that were designated as cash-flow
hedging instruments during 2001. 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 as fair value of financial instruments on the consolidated balance sheets at their fair value. A

substantial portion of Devon’s derivatives consists of contracts that hedge the price of future oil and natural gas production.
These derivative contracts are cash flow hedges that qualify for hedge accounting treatment under SFAS No. 133. 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 these hedging
instruments, net of tax, are recorded directly to stockholders’ equity until the hedged oil or natural gas quantities are produced. To
qualify for hedge accounting treatment, Devon designates its cash flow hedge instruments as such on the date the derivative
contract is entered into or the date of a business combination which includes cash flow hedge instruments. Additionally, Devon
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. If Devon fails to meet the requirements for using hedge accounting treatment, the changes in fair value of these

B e n e a t h t h e S u r f a c e

hedging instruments would not be recorded directly to equity but in the consolidated results of operations. During 2003, 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 interest 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 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 change in the value of a derivative instrument that results from a change in commodity prices or interest
rates. The market risk associated with commodity price and interest rate 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 commodity 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. Devon’s commodity costless price
collars and price swaps have been designated as cash flow hedges. Changes in the fair value of these derivatives are reported on
the balance sheet in AOCI. These amounts are reclassified to oil and gas sales when the forecasted transaction takes place.

During 2003, 2002 and 2001, Devon recorded in its statement of operations a gain of $1 million, a gain of $28 million and a
loss of $2 million, respectively, for the change in the 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, 2003, $150 million of net deferred losses on derivative instruments accumulated in AOCI are expected

to be reclassified to earnings during the next 12 months assuming no change in the December 31, 2003, commodity prices.
Transactions and events expected to occur over the next 12 months that will necessitate reclassifying these derivatives’ losses to
earnings are primarily the production and sale of oil and gas which includes the production hedged under the various derivative
instruments. Presently, the maximum term over which Devon has hedged 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 is 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 2003, 2002 and 2001 pro forma net earnings
and pro forma net earnings per share would have differed from the amounts actually reported as shown in the following table.

Net earnings available to common shareholders, as reported
Add stock-based employee compensation expense included

in reported net earnings, net of related tax expense

Deduct total stock-based employee compensation expense
determined under fair value based method for all awards
(see Note 11), net of related tax expense

Net earnings available to common shareholders, pro forma

Net earnings per share available to common shareholders:

As reported:
Basic
Diluted
Pro forma:
Basic
Diluted

Income Taxes

YEAR ENDED DECEMBER 31,

2003

2002

2001

(IN MILLIONS, EXCEPT PER SHARE DATA)

1,737

(23)
1,716

8.32
8.07

8.22
7.98

$
$

(17)
78

0.61
0.61

0.51
0.50

(15)
79

0.73
0.72

0.62
0.61

Devon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of
assets and liabilities and their respective tax bases, as well as the future tax consequences attributable to the future utilization of

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

existing tax net operating loss and other types of carryforwards. Deferred tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected
to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date. U.S. deferred income taxes have not been provided on undistributed earnings of
foreign operations which are being permanently reinvested.

General and Administrative Expenses

General and administrative expenses are reported net of amounts reimbursed by 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.

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), if the preferred stock of a
subsidiary were converted to common stock and if Devon’s zero coupon convertible senior debentures were converted to
common stock.

The following table reconciles the net earnings and common shares outstanding used in the calculations of basic and

diluted earnings per share for 2003, 2002 and 2001.

Year Ended December 31, 2003

Basic earnings per share
Dilutive effect of potential common shares

issuable upon the exercise of outstanding
stock options

Dilutive effect of potential common shares
issuable upon conversion of preferred
stock of subsidiary acquired in 2003 merger

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 $6 million)

Diluted earnings per share

Year Ended December 31, 2002

Basic earnings per share
Dilutive effect of potential common shares

issuable upon the exercise of outstanding
stock options

Diluted earnings per share

Year Ended December 31, 2001

Basic earnings per share
Dilutive effect of potential common shares

issuable upon the exercise of outstanding
stock options

Diluted earnings per share

NET EARNINGS
APPLICABLE TO
COMMON
STOCKHOLDERS

WEIGHTED
AVERAGE
COMMON SHARES
OUTSTANDING

NET
EARNINGS
PER SHARE

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

1,737

209

8.32

—

9
1,748

—
94

—
93

4
217

155

1
156

128

2
130

8.07

0.61

0.73

0.72

The senior convertible debentures included in the 2003 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

5
$ 49.91 – $89.66
56.10
$

5
$ 45.49 – $89.66
50.85
$

3
$ 48.13 – $89.66
56.11
$

The excluded options for 2003 expire between January 12, 2004, and September 9, 2012.

2003

2002

2001

B e n e a t h t h e S u r f a c e

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 AOCI.

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 14 for a discussion of amounts recorded for
these liabilities.

Impact of Recently Issued Accounting Standards Not Yet Adopted

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest

Entities, (“FIN 46R”) which addresses how a business enterprise should evaluate whether it has a controlling financial interest in
an entity through means other than voting rights and accordingly should consolidate the entity. FIN 46R replaces FASB
Interpretation No. 46, Consolidation of Variable Interest Entities, which was issued in January 2003. Devon will be required to
apply FIN 46R to variable interests in variable interest entities (“VIEs”) created after December 31, 2003. For variable interests in
VIEs created before January 1, 2004, FIN 46R will be applied beginning on January 1, 2005. For any VIEs that must be
consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE
initially would be measured at their carrying amounts with any difference between the net amount added to the consolidated
balance sheet and any previously recognized interest being recognized as the cumulative effect of a change in accounting
principle. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to
measure the assets, liabilities and noncontrolling interest of the VIE. Devon owns no interests in variable interest entities;
therefore, FIN 46R will not affect Devon’s consolidated financial statements.

SFAS Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,
(“SFAS No. 150”) was issued in May 2003. SFAS No. 150 establishes standards for the classification and measurement of certain
financial instruments with characteristics of both liabilities and equity. SFAS No. 150 also includes required disclosures for
financial instruments within its scope. SFAS No. 150 was effective for instruments entered into or modified after May 31, 2003
and otherwise will be effective as of January 1, 2004, except for mandatorily redeemable financial instruments. For certain
mandatorily redeemable financial instruments, SFAS No. 150 will be effective on January 1, 2005. The effective date has been
deferred indefinitely for certain other types of mandatorily redeemable financial instruments. Devon currently does not have any
financial instruments that are within the scope of SFAS No. 150.

BUSINESS COMBINATIONS AND PRO FORMA INFORMATION

Ocean Energy, Inc

On April 25, 2003, Devon completed its merger with Ocean Energy, Inc. (“Ocean”). In the transaction, Devon issued

0.414 shares of its common stock for each outstanding share of Ocean common stock (or a total of approximately 74
million shares). Also, Devon assumed approximately $1.8 billion of debt (current and long-term) from Ocean.

Devon acquired Ocean primarily for the significant production, development projects and exploration prospects in both the

deepwater Gulf of Mexico and internationally and the additional producing assets onshore in the United States and in the
shallower shelf regions of the Gulf of Mexico.

The calculation of the purchase price and the preliminary allocation to assets and liabilities as of April 25, 2003, are shown

below. The purchase price allocation is preliminary because certain items such as the determination of the final tax bases and the
fair value of certain assets and liabilities as of the acquisition date have not been completed.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Calculation and allocation of purchase price:

Shares of Devon common stock issued to Ocean stockholders
Average Devon stock price
Fair value of common stock issued
Plus estimated merger costs incurred
Plus fair value of Ocean convertible preferred stock assumed

by a Devon subsidiary

Plus fair value of Ocean employee stock options assumed by Devon

Total purchase price

Plus fair value of liabilities assumed by Devon:

Current liabilities
Long-term debt
Deferred revenue
Asset retirement obligation, long-term
Other noncurrent 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
Other property and equipment
Other noncurrent assets
Goodwill (none deductible for income taxes)
Total fair value of assets acquired

Mitchell Energy & Development Corp.

(IN MILLIONS, EXCEPT SHARE PRICE)

74
48.05
3,546
114

64
124
3,848

642
1,436
97
121
86
989
7,219

269
4,262
1,060
84
38
1,506
7,219

$
$

On January 24, 2002, Devon completed its merger with 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 8).

Devon acquired Mitchell primarily 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 merger 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

30
50.95
1,512

1,573

3,085
84
27
3,196

190
506
12
798
4,818

169
1,535
639
1,000
15
103
1,357
4,818

$
$

B e n e a t h t h e S u r f a c e

Pro Forma Information

Set forth in the following table is certain unaudited pro forma financial information for the years ended December 31, 2003,
and 2002. The information has been prepared assuming the Ocean and Mitchell mergers were consummated on January 1, 2002.
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, 2002. The pro forma information
also should not be used as an indication of the future results that Devon will achieve after the transactions.

PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
2003

2002

(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

equipment

Accretion of asset retirement obligation
General and administrative expenses
Reduction of carrying value of oil and gas properties

Total operating costs and expenses

Earnings from operations

Other Income (Expenses)

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)

Total 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 stockholders

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

1,840
4,155
416
1,461
7,872

948
219
219
1,174

1,984
38
340
111
5,033

2,839

(515)
(3)
69
1
—
40
(408)

2,431

219
372
591

1,840

—
—
—

1,840
29
1,869
10
1,859

1,549
2,655
304
1,069
5,577

835
190
148
873

1,862
—
321
727
4,956

621

(582)
(3)
1
28
(205)
32
(729)

(108)

47
(199)
(152)

54
9
45

89
—
89
10
79

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

PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,
2003

2002

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

7.90
—
0.12
8.02

7.69
—
0.12
7.81

232
240

72
913
23
247

0.15
0.20
—
0.35

0.14
0.19
—
0.33

229
236

70
927
22
247

COMPREHENSIVE INCOME OR LOSS

Devon’s comprehensive income or loss information is included in the accompanying consolidated statements of

stockholders’ equity and comprehensive income (loss). A summary of accumulated other comprehensive income or loss as of
December 31, 2003, 2002 and 2001, 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
(IN MILLIONS)

UNREALIZED
GAIN (LOSS) ON
MARKETABLE
SECURITIES

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

Balance as of December 31, 2002

2003 activity
Deferred taxes
2003 activity, net of deferred taxes

(38)
(107)
—
(107)

(145)
46
—
46

(99)
894
(128)
766

—
243
(84)
159

159
(379)
123
(256)

(97)
(41)
3
(38)

Balance as of December 31, 2003

667

(135)

—
(28)
11
(17)

(17)
(85)
31
(54)

(71)
28
(9)
19

(52)

(47)
36
(14)
22

(25)
41
(16)
25

—
141
(52)
89

TOTAL

(85)
144
(87)
57

(28)
(377)
138
(239)

(267)
1,022
(186)
836

569

The 2002 activity for unrealized gain (loss) on marketable securities includes additional unrealized losses of $164 million

($103 million net of taxes), offset by the recognition of a $205 million loss ($128 million net of taxes) in the statement of
operations during 2002. The recognized loss was due to the impairment of the ChevronTexaco common stock owned by Devon.

B e n e a t h t h e S u r f a c e

SUPPLEMENTAL CASH FLOW INFORMATION

Cash payments (refunds) for interest and income taxes in 2003, 2002 and 2001 are presented below:

YEAR ENDED DECEMBER 31,
2002

2003

2001

Interest paid
Income taxes paid (refunded)

(IN MILLIONS)

$
$

508
123

248
(12)

118
185

The 2003 Ocean merger, 2002 Mitchell merger and the 2001 acquisition of Anderson Exploration Ltd. involved non-cash

consideration as presented below:

Value of common stock issued
Convertible preferred stock assumed
Employee stock options assumed
Liabilities assumed
Deferred tax liability created
Fair value of assets acquired with

non-cash consideration

ACCOUNTS RECEIVABLE

The components of accounts receivable included the following:

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

Allowance for doubtful accounts

Net accounts receivable

OCEAN
MERGER

MITCHELL
MERGER

ANDERSON
ACQUISITION

(IN MILLIONS)

3,546
64
124
2,382
989

7,105

1,512
—
27
824
798

3,161

—
—
—
1,301
1,394

2,695

DECEMBER 31,

2003

2002

(IN MILLIONS)

668
124
106
59
957
(11)
946

422
102
73
52
649
(10)
639

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Property and equipment included the following:

Oil and gas properties:

Subject to amortization
Not subject to amortization:

Acquired in 2003
Acquired in 2002
Acquired in 2001
Acquired prior to 2001

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

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

DECEMBER 31,

2003

2002

(IN MILLIONS)

23,590

15,020

1,246
636
1,278
176
(9,967)
16,959
1,620
(245)
1,375

—
730
1,338
221
(7,796)
9,513
1,477
(138)
1,339

18,334

10,852

The costs not subject to amortization relate to unproved properties which are excluded from amortized capital costs until it

is determined whether or not proved reserves can be assigned to such properties. The excluded properties are assessed for
impairment at least annually. Subject to industry conditions, evaluation of most of these properties, and the inclusion of their
costs in the amortized capital costs is expected to be completed within five years.

Depreciation, depletion and amortization of property and equipment consisted of the following components:

YEAR ENDED DECEMBER 31,
2002

2003

2001

Depreciation, depletion and amortization of oil and gas properties
Depreciation and amortization of other property and equipment
Amortization of other assets

Total

1,668
118
7
1,793

(IN MILLIONS)

1,106
97
8
1,211

793
30
8
831

As described in Note 1, effective January 1, 2003, Devon adopted SFAS No. 143 and began recording asset retirement
obligations for estimated property and equipment dismantlement, abandonment and restoration costs when the legal obligation is
incurred. In accordance with SFAS No. 143, oil and gas properties subject to amortization and other property and equipment
listed above include asset retirement costs associated with these asset retirement obligations. Following is a reconciliation of the
asset retirement obligation from December 31, 2002, to December 31, 2003.

Asset retirement obligation as of December 31, 2002

Cumulative effect of change in accounting principle
Asset retirement obligation assumed from Ocean merger
Liabilities incurred
Liabilities settled
Liabilities assumed by others
Accretion expense on discounted obligation
Foreign currency translation adjustment

Asset retirement obligation as of December 31, 2003

Less current portion

(IN MILLIONS)

—
453
134
48
(37)
(4)
36
41

671

Asset retirement obligation, long-term

629

INVESTMENT IN CHEVRONTEXACO CORPORATION COMMON STOCK

In the fourth quarter of 2002, Devon recorded a $205 million other-than-temporary impairment of its investment in
shares of ChevronTexaco common stock. Devon acquired these shares in its August 1999 acquisition of PennzEnergy
Company. The shares are deposited with an exchange agent for possible exchange for $760 million of debentures that

are exchangeable into the ChevronTexaco shares. The debentures, which mature in August 2008, were also assumed by Devon in
the 1999 PennzEnergy acquisition.

At the closing date of the PennzEnergy acquisition, Devon initially recorded the ChevronTexaco common shares at their fair

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.

B e n e a t h t h e S u r f a c e

was 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.

During 2003, the share price of ChevronTexaco common stock has increased to $86.39 at December 31, 2003. As a result,

the market value of Devon’s investment in ChevronTexaco common stock increased $141 million from December 31, 2002, to
December 31, 2003. The changes in the value of the shares since December 31, 2002, net of applicable taxes, have been
recorded directly to stockholders’ equity. However, depending on the future performance of ChevronTexaco’s common stock,
Devon may be required to record additional noncash charges in future periods if the value of such stock declines, and Devon
determines that such declines are other than temporary.

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 due October 15, 2006
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 common stock, due June 27, 2020

Other debentures and notes:

6.75% due February 15, 2004
8.05% due June 15, 2004
7.625% due July 1, 2005
7.25% due July 18, 2005
10.25% due November 1, 2005
2.75% due August 1, 2006
6.55% due August 2, 2006
4.375% due October 1, 2007
10.125% due November 15, 2009
6.75% due March 15, 2011
6.875% due September 30, 2011
7.25% due October 1, 2011
8.25% due July 1, 2018
7.50% due September 15, 2027
7.875% due September 30, 2031
7.95% due April 15, 2032
Other
Fair value adjustment on debt related to interest rate swaps
Net (discount) premium on other debentures and notes

Less amount classified as current
Long-term debt

DECEMBER 31,

2003

2002

(IN MILLIONS)

—
—
635

444
316
(83)

404

211
125
125
135
236
500
155
400
177
400
1,750
350
125
150
1,250
1,000
4
27
82
8,918
338
8,580

—
—
1,135

444
316
(98)

388

211
125
—
111
236
—
127
—
177
400
1,750
—
—
—
1,250
1,000
—
5
(15)
7,562
—
7,562

Maturities of long-term debt as of December 31, 2003, excluding the $1 million of net discounts and the $27 million fair value

adjustment, are as follows (in millions):

2004
2005
2006
2007
2008
2009 and thereafter

Total

337
497
1,291
400
761
5,606
8,892

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

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.

The Tranche A facility matures on October 15, 2004. Devon may borrow funds under the Tranche B facility until June 2, 2004

(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
2, 2004, at the end of the Tranche B Revolving Period, Devon may convert the then outstanding balance under the Tranche B
facility to a one-year term loan by paying the Agent a fee of 25 basis points. The applicable borrowing rate would be at LIBOR
plus 112.5 basis points. On December 31, 2003 and 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, 2003, net of outstanding letters of credit, was
approximately $586 million.

Devon may borrow funds under the $275 million Canadian Facility until June 2, 2004 (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, 2003 and 2002, there were no borrowings under the $275 million Canadian Facility. The available capacity under
the Canadian Facility as of December 31, 2003, net of outstanding letters of credit, was approximately $214 million.

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

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

to six months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Credit
Facilities provide for an annual facility fee of $1.4 million that is payable quarterly in arrears.

The agreements governing the Credit Facilities contain certain covenants and restrictions, including a maximum debt-to-

capitalization ratio. At December 31, 2003, Devon was in compliance with such covenants and restrictions.

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, 2003 and 2002, Devon had no
commercial paper debt outstanding.

$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. 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. The margin is based on Devon’s debt rating. Based on Devon’s current debt rating, the margin is 100 basis points. As of
December 31, 2003, and 2002, the average interest rate on this facility was 2.2% and 2.5%, respectively.

This $3 billion facility was fully borrowed upon the closing of the Mitchell merger on January 24, 2002. As of December 31,

2003, and 2002, the remaining balance outstanding was $0.6 billion and $1.1 billion, respectively. The primary sources of the
repayments were the issuance of $1.5 billion of debt securities, of which $1.3 billion was used to pay down the credit facility with
the remainder used to pay down other debt, and $1.4 billion from the sale of certain oil and gas properties, of which $1.1 billion
was used to pay down the credit facility. The terms of this facility require repayment of the remaining debt balance at maturity in
October 2006. 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, 2003, Devon was in compliance with such covenants and restrictions.

Exchangeable Debentures

The exchangeable debentures consist of $444 million of 4.90% debentures and $316 million of 4.95% debentures. The
exchangeable debentures were issued on August 3, 1998, and mature August 15, 2008. The exchangeable debentures were
callable beginning August 15, 2000, initially at 104.0% of principal and at prices declining to 100.5% of principal on or after
August 15, 2007. The exchangeable debentures are exchangeable at the option of the holders at any time prior to maturity, unless
previously redeemed, for shares of ChevronTexaco common stock. In lieu of delivering ChevronTexaco common stock to an
exchanging debenture holder, Devon may, at its option, pay to such holder an amount of cash equal to the market value of the
ChevronTexaco common stock. At maturity, holders who have not exercised their exchange rights will receive an amount in cash
equal to the principal amount of the debentures.

B e n e a t h t h e S u r f a c e

As of December 31, 2003, 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 $107.20 per share of ChevronTexaco stock.

The exchangeable debentures were assumed as part of the PennzEnergy merger. The fair values of the exchangeable
debentures were determined as of August 17, 1999, based on market quotations. Under SFAS No. 133, the total fair value of the
debentures has been allocated between the interest-bearing debt and the option to exchange ChevronTexaco common stock that
is embedded in the debentures. Accordingly, a discount was recorded on the debentures and is being accreted using the effective
interest method which raised the effective interest rate on the debentures to 7.76%.

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

Following are descriptions of the various other debentures and notes listed in the table presented at the beginning of this note.

6.75% Senior Notes due February 15, 2004 Devon assumed these senior notes in connection with the Mitchell merger. The fair

value of these senior notes approximated the face value. As a result, no premium or discount was recorded on these senior notes.

8.05% Notes due June 15, 2004 In June 1999, Devon issued these notes 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 are general unsecured
obligations of Devon.

Ocean Debt In connection with the Ocean merger, Devon assumed $1.8 billion of debt. The table below summarizes the

debt assumed, the fair value of the debt at April 25, 2003, and the effective interest rate. The premiums and discounts are being
amortized or accreted using the effective interest method. All of the notes are general unsecured obligations of Devon.

DEBT ASSUMED

Revolving credit line
Note payable
Senior notes and senior subordinated notes:

Less amount classified as current as of April 25, 2003
Long-term debt

APRIL 25, 2003
FAIR VALUE OF EFFECTIVE RATE OF
DEBT ASSUMED

DEBT ASSUMED

(IN MILLIONS)

160
50

102
139
410
208
406
147
169
6
1,797
361
1,436

4.8%
3.0%
3.8%
7.4%
4.9%
5.5%
6.5%

Change of control provisions required the outstanding borrowings under the credit facility and note payable to be fully paid

immediately. Additionally, Devon was required to extend purchase offers for certain senior notes and the senior subordinated
notes. As a result of these purchase offers, which expired on June 13, 2003, Devon paid $118 million for the aggregate principal
amount tendered. The purchase price for each offer was 101 percent of the principal amount of the notes tendered plus accrued
and unpaid interest to and including the purchase date. All notes that were not tendered remain outstanding except as
described below.

Included in the $118 million of debt retired pursuant to the purchase offer were $13 million of the 8.375% notes and $57
million of the 7.875% notes. The remaining $195 million of 8.375% notes were called and redeemed on July 1, 2003. Additionally,
the remaining $43 million of 7.875% senior notes were paid August 1, 2003, when they were due.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Anderson Debt In connection with the Anderson acquisition, Devon assumed $702 million of senior notes. The table below

summarizes the debt assumed which remains outstanding, the fair value of the debt at October 15, 2001, and the effective
interest rate of the debt assumed after determining the fair values of the respective notes using October 15, 2001, market interest
rates. The premiums and discounts are being amortized or accreted using the effective interest method. All of the notes are
general unsecured obligations of Devon.

DEBT ASSUMED

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

FAIR VALUE OF EFFECTIVE RATE OF
DEBT ASSUMED

DEBT ASSUMED

(IN MILLIONS)

$
$
$

116
129
400

6.3%
6.5%
6.8%

2.75% Notes due August 1, 2006 On August 4, 2003, Devon issued these notes which are unsecured and unsubordinated

obligations of Devon. The proceeds from the issuance of these debt securities, net of discounts and issuance costs, of $498
million, were used to repay amounts outstanding under the $3 billion term loan credit facility.

10.25% Debentures due November 1, 2005, and 10.125% Debentures due November 15, 2009 These debentures were

assumed as part of the PennzEnergy acquisition. The fair values of the respective debentures were determined using August 17,
1999, market interest rates. As a result, premiums were recorded on these debentures which lowered their effective interest rates
to 8.3% and 8.9% on the $236 million of 10.25% debentures and $177 million of 10.125% debentures, respectively. The
premiums are being amortized using the effective interest method.

6.875% Notes due September 30, 2011, and 7.875% Debentures due September 30, 2031 On October 3, 2001, Devon,

through Devon Financing, sold these notes and debentures which 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%.

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

Interest Expense

Following are the components of interest expense for the years 2003, 2002 and 2001:

YEAR ENDED DECEMBER 31,
2002

2003

2001

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

531
3
1
12
(50)
—
5
502

(IN MILLIONS)

499
13
2
8
(4)
8
7
533

200
10
1
3
(3)
7
2
220

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. Changes in the exchange rate between the U.S. dollar
and the Canadian dollar from the dates the notes were assumed as part of an acquisition to the date 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 and certain cash and other working capital amounts of Devon’s Canadian subsidiary which are also
denominated in U.S. dollars are required to be included in determining net earnings for the period in which the exchange rate
changed. As a result of changes in the rate of conversion of Canadian dollars to U.S. dollars, $69 million and $1 million was recorded
as a reduction of expense in 2003 and 2002, respectively, and $11 million was recorded as an increase of expense in 2001.

B e n e a t h t h e S u r f a c e

INCOME TAXES

At December 31, 2003, 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 – Azerbaijan
Net operating loss – China
Minimum tax credits

YEARS OF
EXPIRATION

CARRYFORWARD
AMOUNTS

(IN MILLIONS)

2014 – 2023
2004 – 2022
2005 – 2009
Indefinite
2004 – 2008
Indefinite

$ 611
$ 346
$ 473
67
$
19
$
56
$

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 2003, 2002 and

2001 were as follows:

YEAR ENDED DECEMBER 31,
2002

2003

2001

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)

1,603
603
39
2,245

125
6
(9)
71
193

360
17
(16)
(40)
321

514

(IN MILLIONS)

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)

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) from continuing operations before income taxes and cumulative effect of change in accounting principle as a
result of the following:

YEAR ENDED DECEMBER 31,
2002

2003

2001

Expected income tax expense (benefit) based on U.S. statutory

tax rate of 35%

Financial expenses not deductible for income tax purposes
Dividends received deduction
Nonconventional fuel source credits
State income taxes
Taxation on foreign operations
Effect of Canadian tax rate reduction
Other
Total income tax expense (benefit)

786
1
(5)
—
15
(78)
(218)
13
514

(IN MILLIONS)

(47)
—
(5)
(19)
7
(121)
—
(8)
(193)

10
12
(5)
(19)
4
5
—
(2)
5

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

During 2003, the Canadian government enacted a statutory tax rate reduction that will be phased in through 2007. As

presented in the table above, this rate reduction resulted in a $218 million benefit being recorded in 2003 related to the lower
tax rates being applied to deferred tax liabilities outstanding as of December 31, 2002.

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at

December 31, 2003, and 2002 are presented below:

Deferred tax assets:

Net operating loss carryforwards
Minimum tax credit carryforwards
Fair value of financial instruments
Asset retirement obligations
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
Long-term debt
Other
Total deferred tax liabilities

Net deferred tax liability

DECEMBER 31,

2003

2002

(IN MILLIONS)

416
56
44
281
85
139
1,021

(5,052)
(190)
(102)
(47)
(5,391)
(4,370)

78
164
46
—
42
53
383

(2,863)
(147)
—
—
(3,010)
(2,627)

As shown in the above table, Devon has recognized $1.0 billion of deferred tax assets as of December 31, 2003. Such
amount consists of $416 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 2014, state net operating loss carryforwards
which expire primarily between 2004 and 2022, Canadian carryforwards which expire primarily between 2005 and 2009,
Azerbaijani carryforwards which have no expiration, Chinese carryforwards which expire primarily between 2004 and 2008 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 2004 and 2009. 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.

PREFERRED STOCK OF A SUBSIDIARY

At December 31, 2003, a subsidiary of Devon created in the Ocean merger had 38,000 shares of convertible

preferred stock. In January 2004, these shares of convertible preferred stock were canceled and converted to
1,098,580 shares of Devon common stock pursuant to an automatic conversion feature of the preferred stock.
The automatic conversion feature was triggered when the closing price of Devon common stock equaled or

exceeded the forced conversion price of $52.39 for 20 consecutive trading days.

B e n e a t h t h e S u r f a c e

STOCKHOLDERS’ EQUITY

The authorized capital stock of Devon consists of 800 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 2003, 15 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.

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, 2003, there were no shares of Series A Junior Preferred Stock issued or outstanding. The Series A Junior Preferred
Stock is entitled to receive cumulative quarterly dividends per share equal to the greater of $10 or 100 times the aggregate per
share amount of all dividends (other than stock dividends) declared on Common Stock since the immediately preceding quarterly
dividend payment date or, with respect to the first payment date, since the first issuance of Series A Junior Preferred Stock.
Holders of the Series A Junior Preferred Stock are entitled to 100 votes per share (subject to adjustment to prevent dilution) on all
matters submitted to a vote of the stockholders. The Series A Junior Preferred Stock is neither redeemable nor convertible. The
Series A Junior Preferred Stock ranks prior to the Common Stock but junior to all other classes of Preferred Stock.

Stock Option Plans

Devon has outstanding stock options issued to key management and professional employees under three stock option

plans adopted in 1993, 1997 and 2003 (the “1993 Plan,” the “1997 Plan” and the “2003 Plan”). Options granted under the 1993
Plan and 1997 Plan remain exercisable by the employees owning such options, but no new options will be granted under these
plans. At December 31, 2003, there were 225,000 and 6,382,000 options outstanding under the 1993 Plan and the 1997 Plan,
respectively.

On April 25, 2003, Devon’s stockholders adopted the 2003 Long-Term Incentive Plan. The new long-term incentive plan

authorizes the compensation committee of Devon’s board of directors to grant nonqualified and incentive stock options, stock
appreciation rights, restricted stock awards, performance units and performance bonuses to selected employees. The plan also
authorizes the grant of nonqualified stock options and restricted stock awards to directors. A total of 12,500,000 shares of Devon
common stock have been reserved for issuance pursuant to the plan. Of these shares, no more than 2,500,000 shares may be
granted as restricted stock, performance bonuses and performance units. During 2003, 653,000 restricted stock awards were
granted which are subject to pro rata vesting over a four-year period. These awards had an aggregate fair value of $34 million and
will be recorded as compensation expense over the vesting period.

The exercise price of stock options granted under the 2003 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 eight years from the date of grant. Under the 2003 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 2003 Plan is administered by a committee comprised
of non-management members of the board of directors. The 2003 Plan expires on April 25, 2013. As of December 31, 2003, there
were 1,487,000 options outstanding under the 2003 Plan. There were 10,360,000 options available for future grants as of
December 31, 2003.

In addition to the stock options outstanding under the 1993 Plan, 1997 Plan and 2003 Plan there were approximately

4,674,000, 1,123,000, 281,000 and 1,173,000 stock options outstanding at the end of 2003 that were assumed as part of the
Ocean merger, the Mitchell merger, the Santa Fe Snyder merger and the PennzEnergy merger, respectively.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

A summary of the status of Devon’s stock option plans as of December 31, 2001, 2002 and 2003, and changes during each

of the years then ended, is presented below.

OPTIONS OUTSTANDING

OPTIONS EXERCISABLE

Balance at December 31, 2000

Options granted
Options exercised
Options forfeited

Balance at December 31, 2001

Options granted
Options assumed in the Mitchell merger
Options exercised
Options forfeited

Balance at December 31, 2002

Options granted
Options assumed in the Ocean merger
Options exercised
Options forfeited

Balance at December 31, 2003

NUMBER
OUTSTANDING

(IN THOUSANDS)

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

8,184
2,807
1,554
(899)
(415)

11,231
1,504
7,926
(4,866)
(450)

15,345

WEIGHTED
AVERAGE
EXERCISE
PRICE

$
$
$
$

$
$
$
$
$

41.84
35.43
31.13
62.77

41.09
45.77
26.82
29.33
47.12

41.00
52.75
39.69
33.50
52.11

43.53

WEIGHTED
AVERAGE
EXERCISE
PRICE

NUMBER
EXERCISABLE

(IN THOUSANDS)

6,025

40.72

5,516

41.93

6,991

40.05

11,460

42.61

The weighted average fair values of options granted during 2003, 2002 and 2001 were $16.27, $15.25 and $13.17,
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 2003, 2002 and 2001, respectively: risk-free interest rates of
2.8%, 3.2% and 3.8%; dividend yields of 0.4%, 0.4% and 0.6%; expected lives of four, five and five years; and volatility of the
price of the underlying common stock of 37.9%, 41.8% and 42.2%.

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

exercisable, as of December 31, 2003:

OPTIONS OUTSTANDING

OPTIONS EXERCISABLE

RANGE OF EXERCISE PRICES

$9.68 - $30.94
$31.00 - $36.90
$37.22 - $45.08
$45.10 - $46.09
$46.27 - $51.70
$51.75 - $56.19
$56.68 - $89.66

WEIGHTED
AVERAGE
REMAINING
LIFE

WEIGHTED
AVERAGE
EXERCISE
PRICE

NUMBER
OUTSTANDING

(IN THOUSANDS)

2,172
2,560
2,096
2,753
2,317
2,339
1,108
15,345

2.52 Years
5.23 Years
3.97 Years
6.27 Years
5.05 Years
4.80 Years
3.36 Years
4.65 Years

$ 20.91
$ 35.01
$ 42.78
$ 46.03
$ 50.32
$ 53.74
$ 66.96
$ 43.53

NUMBER
EXERCISABLE

(IN THOUSANDS)

2,172
1,761
2,049
1,234
2,139
1,003
1,102
11,460

WEIGHTED
AVERAGE
EXERCISE
PRICE

$ 20.91
$ 35.09
$ 42.87
$ 45.96
$ 50.30
$ 54.94
$ 67.01
$ 42.61

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 $.01 per right

until the rights become exercisable.

B e n e a t h t h e S u r f a c e

Dividends

Dividends on Devon’s common stock were paid in 2003, 2002 and 2001 at a per share rate of $0.05 per quarter.

FINANCIAL INSTRUMENTS

The following table presents the carrying amounts and estimated fair values of Devon’s financial instrument

assets (liabilities) at December 31, 2003, and 2002.

Investments
Oil and gas price hedge agreements
Interest rate swap agreements
Electricity hedge agreements
Foreign exchange hedge agreements
Embedded option in exchangeable

debentures
Long-term debt
Preferred stock of a subsidiary

2003

CARRYING
AMOUNT

FAIR
VALUE

2002

CARRYING
AMOUNT

FAIR
VALUE

(IN MILLIONS)

$
$
$
$
$

$
$
$

620
(186)
18
(1)
—

(9)
(8,918)
(55)

620
(186)
18
(1)
—

(9)
(9,680)
(63)

479
(144)
(5)
(2)
(1)

(12)
(7,562)
—

479
(144)
(5)
(2)
(1)

(12)
(8,425)
—

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, 2003, and 2002.

Investments — The fair values of investments are based on quoted market prices.

Oil and Gas Price Hedge Agreements — The fair values of the oil and gas price hedges are based on either (a) an internal
discounted cash flow calculation, (b) quotes obtained from the counterparty to the hedge agreement or (c) quotes provided by
brokers.

Interest Rate Swap Agreements — The fair values of the interest rate swaps are based on quotes obtained from the

counterparty to the swap agreement.

Electricity Hedge Agreements — The fair values of the electricity hedges are based on an internal discounted cash flow

calculation.

Foreign Exchange Hedge Agreements — The fair values of the foreign exchange agreements are based on either (a) an

internal discounted cash flow calculation or (b) quotes obtained from brokers.

Embedded Option in Exchangeable Debentures — The fair values of the embedded options are based on quotes obtained

from brokers.

Long-term Debt — The fair values of the fixed-rate long-term debt have been estimated based on quotes obtained from
brokers or by discounting the principal and interest payments at rates available for debt of similar terms and maturity. The fair
values of the floating-rate long-term debt are estimated to approximate the carrying amounts due to the fact that the interest
rates paid on such debt are generally set for periods of three months or less.

Preferred Stock of a Subsidiary — The fair value of the preferred stock is based upon quotes obtained from brokers.

Devon’s total hedged positions as of December 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 oil and natural gas production in

2004 and 2005. These swaps will result in the fixed prices included below. Where necessary, the gas 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.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

YEAR

2004
2005

YEAR

2004
2005

OIL PRODUCTION

BBLS/DAY

64,000
22,000

PRICE
PER BBL

$ 26.95
$ 26.84

GAS PRODUCTION

MCF/DAY

8,435
7,343

PRICE
PER MCF

$
$

3.10
2.97

Costless Price Collars

Devon has also entered into costless price collars that set a floor and ceiling price for a portion of its 2004 and 2005 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. The floor and ceiling prices related to international oil production are based on the
Brent price. If the NYMEX or Brent 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 or Brent 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.

prices and similar ceiling prices. The floor and ceiling prices shown are weighted averages of the various collars in each
aggregated group.

The international oil prices shown in the following tables have been adjusted to a NYMEX-based price, using Devon’s

estimates of future differentials between NYMEX and the Brent price upon which the collars are based.

The natural gas prices shown in the following tables have been adjusted to a NYMEX-based price, using Devon’s estimates

YEAR

2004
2005

YEAR

2004
2005

OIL PRODUCTION

BBLS/DAY

77,000
50,000

WEIGHTED AVERAGE

FLOOR PRICE
PER BBL

CEILING PRICE
PER BBL

$
$

21.90
22.23

$
$

30.28
28.23

GAS PRODUCTION

MMBTU/DAY

WEIGHTED AVERAGE

FLOOR PRICE
PER MMBTU

CEILING PRICE
PER MMBTU

1,194,945
94,548

$
$

4.02
3.83

$
$

7.43
7.20

Interest Rate Swaps

Devon has also entered into a floating-to-fixed interest rate swap and fixed-to-floating interest rate swaps. Under the
floating-to-fixed interest rate swap, Devon will record a fixed rate of 6.4% on a notional amount of $97 million in 2004 through
2006 and 6.3% on a notional amount of $30 million in 2007. Following is a table summarizing the fixed-to-floating interest rate
swaps with the related debt instrument and notional amounts.

B e n e a t h t h e S u r f a c e

DEBT INSTRUMENT

NOTIONAL AMOUNT

FLOATING RATE

4.375% senior notes due in 2007
10.25% bond due in 2005
8.05% senior notes due in 2004
2.75% notes due in 2006
7.625% senior notes due in 2005

RETIREMENT PLANS

(IN MILLIONS)

$
$
$
$
$

400
235
125
500
125

LIBOR plus 40 basis points
LIBOR plus 711 basis points
LIBOR plus 336 basis points
LIBOR less 26.8 basis points
LIBOR plus 237 basis points

Devon has various non-contributory defined benefit pension plans, including qualified plans (“Qualified Plans”)

and nonqualified plans (“Supplemental Plans”). The Qualified Plans provide retirement benefits for U.S. and
Canadian employees meeting certain age and service requirements. Benefits for the Qualified Plans are based on
the employee’s years of service and compensation and are funded from assets held in the plans’ trusts.
During 2002, Devon established a funding policy regarding the Qualified Plans such that it would contribute the amount of
funds necessary so that the Qualified Plans’ assets would be approximately equal to the related accumulated benefit obligation
by the end of 2004. As of December 31, 2003, the Qualified Plans’ total accumulated benefit obligation was $397 million, which
was $22 million more than the related assets. Devon’s intentions are to fund this deficit during 2004. The actual amount of
contributions required during this period will depend on investment returns from the plan assets during the same period as well as
changes in long-term interest rates.

The Supplemental Plans provide retirement benefits for certain employees whose benefits under the Qualified Plans are

limited by income tax regulations. The Supplemental Plans’ benefits are based on the employee’s years of service and
compensation. For certain Supplemental Plans, Devon has established trusts to fund these plans’ benefit obligations. The total
values of these trusts were $66 million and $53 million at December 31, 2003, and 2002, respectively, and are included in
noncurrent other assets in the consolidated balance sheets. For the remaining Supplemental Plans for which trusts have not been
established, benefits are funded from Devon’s available cash and cash equivalents.

Devon also has defined benefit postretirement plans (“Postretirement Plans”) which provide benefits for substantially all
employees. The Postretirement Plans provide medical and, in some cases, life insurance benefits, and are, depending on the type
of plan, either contributory or non-contributory. Benefit obligations for the Postretirement Plans are estimated based on future
cost-sharing changes that are consistent with Devon’s expressed intent to increase, where possible, contributions from future
retirees. Devon’s funding policy for the Postretirement Plans is to fund the benefits as they become payable with available cash
and cash equivalents recorded in the consolidated balance sheet.

Benefit Obligations

Devon uses a measurement date of December 31 for its pension and postretirement benefit plans. The following table presents

the plans’ benefit obligations and the weighted-average actuarial assumptions used to calculate such obligations at December 31,
2003, and 2002. The benefit obligation for pension plans represents the projected benefit obligation, while the benefit obligation
for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from
the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated
benefit obligation for pension plans at December 31, 2003, and 2002 was $475 million and $424 million, respectively.

Change in benefit obligation:

Benefit obligation at beginning of year
Service cost
Interest cost
Participant contributions
Amendments
Mergers and acquisitions
Foreign exchange rate changes
Settlement payments
Curtailment loss
Actuarial loss
Benefits paid
Benefit obligation at end of year

Actuarial assumptions:

Discount rate
Rate of compensation increase

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

PENSION BENEFITS
2002
2003

OTHER POSTRETIREMENT
BENEFITS

2003

2002

(IN MILLIONS)

460
12
31
—
1
19
4
—
—
28
(43)
512

210
9
28
—
—
208
—
(15)
2
42
(24)
460

69
1
4
1
(1)
—
—
—
—
3
(7)
70

33
1
4
1
—
30
—
—
—
6
(7)
68

6.23%
4.88%

6.72%
4.88%

6.25%
5.00%

6.75%
5.00%

For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care benefits was

assumed for 2004. The rate was assumed to decrease on a pro-rata basis annually to 5% in the year 2008 and remain at that
level thereafter. A one-percentage-point increase in assumed health care cost trend rates would increase the December 31, 2003,
postretirement benefit obligation by $2 million, while a one-percentage-point decrease in the same rate would decrease the
postretirement benefit obligation by $3 million.

Plan Assets

The following table presents the plans’ assets at December 31, 2003, and 2002.

Change in plan assets:

Fair value of plan assets at beginning of year
Actual return on plan assets
Mergers and acquisitions
Employer contributions
Participant contributions
Settlement payments
Transfer to defined contribution plan
Benefits paid
Foreign exchange rate changes

Fair value of plan assets at end of year

PENSION BENEFITS
2002
2003

OTHER POSTRETIREMENT
BENEFITS

2003

2002

(IN MILLIONS)

281
70
—
67
—
—
(3)
(43)
3
375

156
(47)
145
66
—
(15)
—
(24)
—
281

—
—
—
6
1
—
—
(7)
—
—

The plan assets for pension benefits in the table above excludes the assets held in trusts for the Supplemental Plans.
However, employer contributions for pension benefits in the table above include $22 million in 2003 and $20 million in 2002 which
were transferred from the trusts established for the Supplemental Plans.

Devon’s overall investment objective for its retirement plans’ assets is to achieve long-term growth of invested capital to
ensure payments of retirement benefits obligations can be funded when required. To assist in achieving this objective, Devon has
established certain investment strategies, including target allocation percentages and permitted and prohibited investments,
designed to mitigate risks inherent with investing. At December 31, 2003, the target investment allocation for Devon’s plan assets
is 50% U.S. large cap equity securities; 15% U.S. small cap equity securities, equally allocated between growth and value; 15%
international equity securities, equally allocated between growth and value; and 20% debt securities. Derivatives or other
speculative investments considered high-risk are generally prohibited.

The asset allocation for Devon’s retirement plans at December 31, 2003, and 2002, and the target allocation for 2004, by

asset category, follows:

Equity securities
Debt securities
Other

Total

TARGET
ALLOCATION
2004

PERCENTAGE OF PLAN
ASSETS AT YEAR END

2003

2002

80%
20%
—
100%

79%
19%
2%
100%

75%
23%
2%
100%

B e n e a t h t h e S u r f a c e

Funded Status

The following table presents the funded status of the plans and the net amounts recognized in the consolidated balance sheets

at December 31, 2003, and 2002.

Net amounts recognized in consolidated

balance sheets:
Fair value of plan assets
Benefit obligations
Funded status
Unrecognized net actuarial loss
Unrecognized prior service cost (benefit)

Net amounts recognized

Components of net amounts recognized
in the consolidated balance sheets:
Accrued benefit cost
Intangible asset
Accumulated other comprehensive income

Net amount recognized

PENSION BENEFITS
2002
2003

OTHER POSTRETIREMENT
BENEFITS

2003

2002

(IN MILLIONS)

375
512
(137)
119
5
(13)

(102)
4
85
(13)

281
460
(179)
152
5
(22)

(140)
5
113
(22)

—
70
(70)
11
(2)
(61)

(61)
—
—
(61)

—
68
(68)
8
(1)
(61)

(61)
—
—
(61)

During 2003, the change in the minimum pension liability increased other comprehensive income by $28 million. During
2002, and 2001, the changes in the minimum pension liability decreased other comprehensive income by $85 million and $28
million, respectively.

Certain of Devon’s pension and postretirement plans have a projected benefit obligation in excess of plan assets at
December 31, 2003, and 2002. The aggregate benefit obligation and fair value of plan assets for these plans is included below.

Projected benefit obligation
Fair value of plan assets

DECEMBER 31,
2002
2003

(IN MILLIONS)

571
359

519
265

Certain of Devon’s pension plans have an accumulated benefit obligation in excess of plan assets at December 31, 2003,

and 2002. The aggregate accumulated benefit obligation and fair value of plan assets for these plans is included below.

Accumulated benefit obligation
Fair value of plan assets

DECEMBER 31,
2002
2003

(IN MILLIONS)

465
359

415
265

The plan assets included in the tables above exclude the Supplemental Plan trusts, which had a total value of $66 million

and $53 million at December 31, 2003, and 2002, respectively.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Net Periodic Cost

The following table presents the plans’ net periodic benefit cost and the weighted-average actuarial assumptions used to

calculate such cost for the years ended December 31, 2003, 2002 and 2001.

PENSION BENEFITS
2002

2003

2001

OTHER POSTRETIREMENT
BENEFITS

(IN MILLIONS)

Employer contributions – 2004

Benefit payments:

2004
2005
2006
2007
2008
2009 – 2013

28
29
30
31
33
192

8
8
8
7
7
30

Expected employer contributions included in the table above include amounts related to Devon’s Qualified Plans,

Supplemental Plans and Postretirement Plans. Of the benefits expected to be paid in 2004, $7 million is expected to be funded
from the trusts established for the Supplemental Plans and $8 million is expected to be funded from Devon’s available cash and
cash equivalents. Expected employer contributions and benefit payments for other postretirement benefits are presented net of
employee contributions.

Other Benefit Plans

Devon has incurred certain postemployment benefits to former or inactive employees who are not retirees. These benefits
include salary continuance, severance and disability health care and life insurance. The accrued postemployment benefit liability
was approximately $6 million at both December 31, 2003, and 2002.

Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a
certain percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the board of
directors. Devon’s matching contributions to the plan were $10 million, $8 million and $5 million for the years ended December
31, 2003, 2002 and 2001, respectively.

B e n e a t h t h e S u r f a c e

Devon has defined contribution pension plans for its Canadian employees. Devon makes a contribution to each employee

which is based upon the employee’s base compensation and classification. Such contributions are subject to maximum amounts
allowed under the Income Tax Act (Canada). Devon also has a savings plan for its Canadian employees. Under the savings plan,
Devon contributes a base percentage amount to all employees and the employee may elect to contribute an additional
percentage amount (up to a maximum amount) which is matched by additional Devon contributions. During 2003, 2002 and 2001,
Devon’s combined contributions to the Canadian defined contribution plan and the Canadian savings plan were $8 million, $8
million and $3 million, respectively.

COMMITMENTS AND CONTINGENCIES

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

future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded
accruals although actual amounts could differ materially from management’s estimate.

Environmental Matters

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

Certain of Devon’s subsidiaries acquired in past mergers are involved in matters in which it has been alleged that such
subsidiaries are potentially responsible parties (“PRPs”) under CERCLA or similar state legislation with respect to various waste
disposal areas owned or operated by third parties. As of December 31, 2003, Devon’s consolidated balance sheet included $9
million of non-current accrued liabilities, reflected in “Other liabilities,” related to these and other environmental remediation
liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the
current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries
are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both other PRPs and the
Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants
not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP and (iii) the availability of other defenses to
liability. As a result, Devon’s monetary exposure is not expected to be material.

Royalty Matters

Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of the
federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper deductions,
improper measurement techniques and transactions with affiliates which resulted in underpayment of royalties in connection with
natural gas and natural gas liquids produced and sold from federal and Indian owned or controlled lands. The principal suit in
which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc. et al. (the “Wright case”). The suit was originally
filed in August 1996 in the United States District Court for the Eastern District of Texas but was consolidated in October 2000 with
the other suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On July 10, 2003, the
District of Wyoming remanded the Wright case back to the Eastern District of Texas to resume proceedings. Devon believes that
it has acted reasonably, has legitimate and strong defenses to all allegations in the suit and has paid royalties in good faith. Devon
does not currently believe that it is subject to material exposure in association with this lawsuit and no liability has been recorded
in connection therewith.

Devon is a defendant in certain private royalty owner litigation filed in Wyoming regarding deductibility of certain post
production costs from royalties payable by Devon. The plaintiffs in these lawsuits propose to expand them into county or state-
wide class actions relating specifically to transportation and related costs associated with Devon’s Wyoming gas production. A
significant portion of such production is, or will be, transported through facilities owned by Thunder Creek Gas Services, L.L.C., of
which Devon owns a 75% interest. Devon believes that it has acted reasonably and paid royalties in good faith and in accordance
with its obligations under its oil and gas leases and applicable law, and Devon does not believe that it is subject to material
exposure in association with this litigation.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Tax Treatment of Exchangeable Debentures

As described more fully in Note 8, Devon has certain exchangeable debentures, with a principal amount totaling $760
million, which are exchangeable at the option of the holders into shares of ChevronTexaco common stock owned by Devon. The
debentures were assumed, and the ChevronTexaco common stock was acquired, by Devon in the 1999 PennzEnergy merger.

The Internal Revenue Service is currently examining the 1998 income tax return of PennzEnergy’s predecessor. In draft
notices, the IRS has disagreed with certain tax treatments of the exchangeable debentures and similar exchangeable debentures
retired in 1998. The IRS has not yet formally asserted a claim for additional taxes for 1998 related to the exchangeable
debentures, but Devon believes it is probable that such an assertion will eventually be made.

Based upon the draft notices received from the IRS, Devon estimates that if the IRS formally asserts a claim for additional

taxes for 1998 as a result of its current examination, the amount of such claim would approximate $68 million.

Devon does not agree with the positions that have been taken by the IRS in its draft documents, and will vigorously contest

any claim of additional taxes. Although the outcome of this matter cannot be predicted with certainty, Devon, after consultation
with legal counsel, believes that if the IRS formally asserts a claim for additional taxes regarding the treatment of the
exchangeable debentures, Devon would likely prevail. Even if the IRS prevailed in this matter, Devon believes that any related
increase in its 1998 taxable income would increase its tax basis in the ChevronTexaco common stock, or produce a similar tax
benefit, and would therefore result in offsetting tax deductions in future taxable years upon the disposal of the ChevronTexaco
common stock. Therefore, while the payment of any such additional taxes would reduce Devon’s operating cash flow in the year
of payment, it would not affect Devon’s net earnings for any period, and the operating cash flow effect would reverse in future
years.

If the IRS ultimately prevailed in this matter, any interest owed by Devon on such additional taxes would negatively impact
Devon’s operating cash flow and net earnings. However, Devon does not believe that such impact would be material to Devon’s
financial condition or results of operations.

Other Matters

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge as of

the date of this report, there were no other material pending legal proceedings to which Devon is a party or to which any of its
property is subject.

Operating Leases

Devon leases certain office space and equipment under operating lease arrangements. Total rental expense included in
general and administrative expenses under operating leases net of sub-lease income was $51 million, $37 million and $17 million
in 2003, 2002 and 2001, respectively.

Devon assumed two offshore platform spar leases through the 2003 Ocean merger. The spars are being used in the
development of the Nansen and Boomvang fields in the Gulf of Mexico. The operating leases are for 20-year terms and contain
various options whereby Devon may purchase the lessors’ interests in the spars. Total rental expense included in lease operating
expenses under these operating leases was $11 million in 2003. Devon has guaranteed that the spars will have residual values at
the end of the operating leases equal to at least 10% of the fair value of the spars at the inception of the leases. The total
guaranteed value is $20 million in 2022. However, such amount may be reduced under the terms of the lease agreements.

Devon also has two floating, production, storage and offloading (FPSO) facilities that are being leased under operating lease

arrangements. One FPSO is being used in the Panyu project offshore China, and the other is being used in the Zafiro field
offshore Equatorial Guinea. The China lease expires in September 2009 and the Equatorial Guinea lease expires in July 2011.
Total rental expense included in lease operating expenses under these operating leases was $6 million in 2003.

The following is a schedule by year of future minimum rental payments required under office and equipment, spar and FPSO

leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31, 2003:

YEAR ENDING DECEMBER 31,

2004
2005
2006
2007
2008
Thereafter

Total minimum lease payments

OFFICE AND
EQUIPMENT
LEASES

SPAR
LEASES

FPSO
LEASES

(IN MILLIONS)

47
40
36
28
24
85
260

11
15
15
15
15
243
314

20
20
20
20
20
36
136

B e n e a t h t h e S u r f a c e

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 and asset retirement obligations, may not exceed a calculated “ceiling.” The ceiling limitation is the
discounted estimated after-tax future net revenues from proved oil and gas properties plus the cost of properties
not subject to amortization. The ceiling is determined separately by country. In calculating future net revenues,

current prices and costs are generally held constant indefinitely. The net book value, less deferred tax liabilities and asset
retirement obligations, is compared to the ceiling on a quarterly and annual basis. Any excess of the net book value, less related
deferred taxes and asset retirement obligations, is written off as an expense. An expense recorded in one period may not be
reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the
subsequent period.

Under the purchase method of accounting for business combinations, acquired oil and gas properties are recorded at

estimated fair value as of the date of purchase. Devon estimates such fair value using its estimates of future oil, gas and NGL
prices. In contrast, the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held
constant indefinitely. Accordingly, the resulting value from the ceiling calculation is not necessarily indicative of the fair value of
the reserves.

During 2003, 2002 and 2001, Devon reduced the carrying value of its oil and gas properties by $68 million, $651 million and

United States
Canada
International

Total

2003

YEAR ENDED DECEMBER 31,
2002

2001

GROSS

NET OF
TAXES

GROSS

NET OF
TAXES

GROSS

NET OF
TAXES

(IN MILLIONS)

—
—
68
68

—
—
36
36

—
651
—
651

—
371
—
371

449
434
—
883

281
252
—
533

The 2003 reduction in carrying value was related to properties in Egypt, Russia and Indonesia. The Egyptian reduction was

primarily due to poor results of a development well that was unsuccessful in the primary objective. Partially as a result of this well,
Devon revised Egyptian proved reserves downward. The Russian reduction was primarily the result of additional capital costs
incurred as well as an increase in operating costs. The Indonesian reduction was primarily related to an increase in operating
costs and a reduction in proved reserves. As a result, Devon’s Egyptian, Russian and Indonesian costs to be recovered exceeded
the related ceiling value by $26 million, $9 million and $1 million, respectively. These after-tax amounts resulted in pre-tax
reductions of the carrying values of Devon’s Egyptian, Russian and Indonesian oil and gas properties of $45 million, $19 million
and $4 million, respectively, in the fourth quarter of 2003.

Additionally, during 2003, Devon elected to discontinue certain exploratory activities in Ghana, certain properties in Brazil
and other smaller concessions. After meeting the drilling and capital commitments on these properties, Devon determined that
these properties did not meet Devon’s internal criteria to justify further investment. Accordingly, Devon recorded a $43 million
charge associated with the impairment of these properties. The after-tax effect of this reduction was $38 million.

The 2002 Canadian reduction was primarily the result of lower prices. The recorded values of oil and gas properties added

from the Anderson acquisition in 2001 were based on expected future oil and gas prices that were higher than the June 30, 2002,
prices used to calculate the Canadian ceiling.

The 2001 domestic and Canadian reductions were also primarily the result of lower prices. The oil and gas properties added

from the Anderson acquisition and other smaller acquisitions in 2001 were recorded at fair values that were based on expected
future oil and gas prices higher than the December 31, 2001, prices used to calculate the ceiling.

Additionally, during 2001, Devon elected to abandon operations in Thailand, Malaysia, Qatar and on certain properties in
Brazil. After meeting the drilling and capital commitments on these properties, Devon determined that these properties did not
meet Devon’s internal criteria to justify further investment. Accordingly, Devon recorded a $96 million charge associated with the
impairment of these properties. The after-tax effect of this reduction was $78 million.

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

DISCONTINUED OPERATIONS

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, Accounting for the Impairment or Disposal of Long-Lived Assets, Devon reclassified

its Indonesian, Argentine and Egyptian activities as discontinued operations. This reclassification affects the 2002 and 2001
presentation of financial results. Subsequent to the sale of its Egyptian and Indonesian operations, Devon acquired new Egyptian
and Indonesian assets in the April 2003 Ocean merger. Amounts and activities related to these new Egyptian and Indonesian
operations are included in Devon’s continuing operations in 2003.

The major classes of assets and liabilities of these discontinued operations as of December 31, 2002, and revenues from

these discontinued operations in 2002 and 2001 are presented below:

Major Classes of Assets and Liabilities
Accounts receivable

Total assets

Revenues
Oil sales
Gas sales
NGL sales

Total revenues

SEGMENT INFORMATION

DECEMBER 31, 2002

(IN MILLIONS)

$
$

7
7

YEAR ENDED
DECEMBER 31,

2002

2001

(IN MILLIONS)

72
7
1
80

174
12
1
187

Devon manages its business by country. As such, Devon identifies its segments based on geographic areas.

Devon has three reportable segments: its operations in the U.S., its operations in Canada and its international
operations outside of North America. Substantially all of these segments’ operations involve oil and gas
producing activities. Certain information regarding such activities for each segment is included in Note 18.

Following is certain financial information regarding Devon’s segments for 2003, 2002 and 2001. The revenues reported are

all from external customers.

As of December 31, 2003
Current assets
Property and equipment, net of accumulated
depreciation, depletion and amortization

Goodwill
Other assets

Total assets

Current liabilities
Other liabilities
Asset retirement obligation, long-term
Long-term debt
Preferred stock of a subsidiary
Deferred income taxes
Stockholders’ equity

Total liabilities and stockholders’ equity

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

1,411

10,753
3,073
908
16,145

1,320
371
386
4,810
55
2,471
6,732
16,145

643

4,900
2,336
27
7,906

458
20
218
3,770
—
1,433
2,007
7,906

310

2,364

2,681
68
52
3,111

293
10
25
—
—
466
2,317
3,111

18,334
5,477
987
27,162

2,071
401
629
8,580
55
4,370
11,056
27,162

B e n e a t h t h e S u r f a c e

Year Ended December 31, 2003
Revenues:
Oil sales
Gas sales
Natural gas liquids 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
Accretion of asset retirement obligation
General and administrative expenses
Expenses related to mergers
Reduction in carrying value of oil and gas properties

Total operating costs and expenses

Earnings from operations
Other income (expenses):

Interest expense
Dividends on subsidiary’s preferred stock
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Other income

Net other income (expenses)

Earnings before income taxes and cumulative effect of change in

accounting principle

Income tax expense (benefit):

Current
Deferred

Total income tax expense (benefit)

Earnings before cumulative effect of change in accounting principle
Cumulative effect of change in accounting principle
Net earnings

Capital expenditures

As of December 31, 2002
Current assets
Property and equipment, net of accumulated
depreciation, depletion and amortization

Goodwill
Other assets

Total assets

Current liabilities
Other liabilities
Long-term debt
Deferred income taxes
Stockholders’ equity

Total liabilities and stockholders’ equity

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

861
2,652
289
1,443
5,245

477
140
194
1,165
1,195
22
252
7
—
3,452
1,793

(211)
(2)
—
2
21
(190)

1,603

131
377
508
1,095
11
1,106

1,579

318
1,222
114
17
1,671

327
65
3
9
399
13
43
—
—
859
812

(285)
—
69
(1)
8
(209)

603

(9)
(16)
(25)
628
5
633

704

409
23
4
—
436

67
2
7
—
199
1
12
—
111
399
37

(6)
—
—
—
8
2

71
(40)
31
8
—
8

304

1,588
3,897
407
1,460
7,352

871
207
204
1,174
1,793
36
307
7
111
4,710
2,642

(502)
(2)
69
1
37
(397)

2,245

193
321
514
1,731
16
1,747

2,587

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

603

6,838
1,565
723
9,729

626
333
3,545
1,520
3,705
9,729

366

3,497
1,921
31
5,815

344
7
4,017
1,062
385
5,815

517
69
—
681

72
1
—
45
563
681

1,064

10,852
3,555
754
16,225

1,042
341
7,562
2,627
4,653
16,225

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

Year Ended December 31, 2002
Revenues:
Oil sales
Gas sales
Natural gas liquids 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
General and administrative expenses
Reduction in carrying value of oil and gas properties

Total operating costs and expenses

Earnings (loss) 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 income (expenses)

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

Current
Deferred

Total income tax expense (benefit)
Earnings (loss) from continuing operations
Discontinued operations:

Results of discontinued operations before income taxes
Income tax expense
Net results of discontinued operations

Net earnings (loss)

Capital expenditures

524
1,403
192
985
3,104

354
99
104
800
834
166
—
2,357
747

(235)
—
31
(205)
16
(393)
354

(23)
42
19
335

—
—
—
335

2,797

331
730
83
14
1,158

255
55
7
8
371
40
651
1,387
(229)

(295)
1
(3)
—
11
(286)
(515)

28
(253)
(225)
(290)

—
—
—
(290)

532

54
—
—
—
54

12
—
—
—
6
13
—
31
23

(3)
—
—
—
7
4
27

18
(5)
13
14

54
9
45
59

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)
59

54
9
45
104

3,426

B e n e a t h t h e S u r f a c e

Year Ended December 31, 2001
Revenues:
Oil sales
Gas sales
Natural gas liquids 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 in carrying value of oil and gas properties

Total operating costs and expenses

Earnings (loss) from operations
Other income (expenses):

Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of financial instruments
Other income

Net other income (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 (loss) from continuing operations before

cumulative effect of change in accounting principle

Discontinued operations:

Results of discontinued operations before income taxes
Income tax expense
Net results of discontinued operations

Earnings (loss) before cumulative effect of change in

accounting principle

Cumulative effect of change in accounting principle
Net earnings (loss)

Capital expenditures

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

586
1,571
103
64
2,324

340
59
113
43

647
34
98
—
449
1,783
541

(139)
—
(1)
57
(83)

458

29
92
121

337

—
—
—

337
49
386

146
307
28
7
488

110
24
3
4

166
—
15
1
434
757
(269)

(81)
(11)
(1)
5
(88)

(357)

8
(145)
(137)

(220)

—
—
—

(220)
—
(220)

52
—
—
—
52

17
—
—
—

18
—
1
—
96
132
(80)

—
—
—
7
7

(73)

11
10
21

(94)

56
25
31

(63)
—
(63)

784
1,878
131
71
2,864

467
83
116
47

831
34
114
1
979
2,672
192

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

48
(43)
5

56
25
31

54
49
103

1,356

3,774

105

5,235

SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

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

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Costs Incurred
The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities:

Property acquisition costs:

Proved business combinations
Deferred income taxes
Total proved

Unproved business combinations
Unproved other acquisitions
Deferred income taxes

Total unproved

Exploration costs
Development costs

Finding and development costs
Asset retirement costs – business combinations
Asset retirement costs – drilling
Less actual retirement expenditures

Costs incurred

Property acquisition costs:

Proved business combinations
Deferred income taxes
Total proved

Unproved business combinations
Unproved other acquisitions
Deferred income taxes

Total unproved

Exploration costs
Development costs

Finding and development costs
Asset retirement costs – business combinations
Asset retirement costs – drilling
Less actual retirement expenditures

Costs incurred

Property acquisition costs:

Proved business combinations
Deferred income taxes
Total proved

Unproved business combinations
Unproved other acquisitions
Deferred income taxes

Total unproved

Exploration costs
Development costs

Finding and development costs
Asset retirement costs – business combinations
Asset retirement costs – drilling
Less actual retirement expenditures

Costs incurred

TOTAL
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

4,209
—
4,209
1,063
87
—
1,150
714
1,853
7,926
134
48
(37)
8,071

1,538
—
1,538
639
64
—
703
383
1,140
3,764
—
—
—
3,764

2,971
84
3,055
1,433
183
27
1,643
337
916
5,951
—
—
—
5,951

DOMESTIC
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

2,582
—
2,582
551
48
—
599
343
1,191
4,715
115
24
(22)
4,832

1,536
—
1,536
639
27
—
666
161
808
3,171
—
—
—
3,171

292
79
371
—
158
27
185
166
726
1,448
—
—
—
1,448

CANADA
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

26
—
26
—
39
—
39
214
488
767
—
17
(14)
770

2
—
2
—
28
—
28
207
299
536
—
—
—
536

2,621
5
2,626
1,433
24
—
1,457
126
168
4,377
—
—
—
4,377

B e n e a t h t h e S u r f a c e

Property acquisition costs:

Proved business combinations
Deferred income taxes
Total proved

Unproved business combinations
Unproved other acquisitions
Deferred income taxes

Total unproved

Exploration costs
Development costs

Finding and development costs
Asset retirement costs – business combinations
Asset retirement costs – drilling
Less actual retirement expenditures

Costs incurred

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

1,601
—
1,601
512
—
—
512
157
174
2,444
19
7
(1)
2,469

—
—
—
—
9
—
9
15
33
57
—
—
—
57

58
—
58
—
1
—
1
45
22
126
—
—
—
126

The preceding Total and International cost incurred tables exclude $16 million and $85 million in 2002 and 2001,

respectively, related to discontinued operations.

As discussed in Note 1, effective January 1, 2003, Devon adopted SFAS No. 143. Prior to the adoption of SFAS No. 143,

asset retirement costs were included in costs incurred when expenditures for such costs were made. Pursuant to the adoption of
SFAS No. 143, such costs are now included in costs incurred when a legal obligation for incurring such costs has occurred.

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses which are

related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in the costs
shown in the preceding tables, were $140 million, $97 million and $77 million in the years 2003, 2002 and 2001, respectively. Also,
pursuant to the full cost method of accounting, Devon capitalizes interest costs incurred and attributable to unproved oil and gas
properties and major development projects of oil and gas properties. Capitalized interest expenses, which are included in the costs
shown in the preceding tables, were $50 million, $4 million and $3 million in the years 2003, 2002 and 2001, respectively.

Results of Operations for Oil and Gas Producing Activities

The following tables include revenues and expenses associated directly with Devon’s oil and gas producing activities,
including general and administrative expenses directly related to such producing activities. They do not include any allocation of
Devon’s interest costs or general corporate overhead and, therefore, are not necessarily indicative of the contribution to net
earnings of Devon’s oil and gas operations. Income tax expense has been calculated by applying statutory income tax rates to oil,
gas and NGL sales after deducting costs, including depreciation, depletion and amortization and after giving effect to permanent
differences.

TOTAL
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

5,892
(1,282)
(1,668)
(36)
—

(48)
(111)
(895)
1,852

7.33

3,317
(886)
(1,106)
—
—

(29)
(651)
(234)
411

5.88

2,793
(666)
(793)
—
(34)

(17)
(979)
(126)
178

6.30

Oil, gas and natural gas liquids sales
Production and operating expenses
Depreciation, depletion and amortization
Accretion of asset retirement obligation
Amortization of goodwill
General and administrative expenses directly related to oil

and gas producing activities

Reduction of carrying value of oil and gas properties
Income tax expense
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

and gas producing activities

Reduction of carrying value of oil and gas properties
Income tax expense
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

Oil, gas and natural gas liquids sales
Production and operating expenses
Depreciation, depletion and amortization
Accretion of asset retirement obligation
General and administrative expenses directly related to oil

and gas producing activities

Reduction of carrying value of oil and gas properties
Income tax (expense) benefit
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

and gas producing activities

Reduction of carrying value of oil and gas properties
Income tax (expense) benefit
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

DOMESTIC
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

3,802
(811)
(1,084)
(22)
—

(27)
—
(775)
1,083

7.42

2,119
(557)
(737)
—
—

(14)
—
(295)
516

6.22

2,260
(512)
(615)
—
(34)

(9)
(449)
(263)
378

6.48

CANADA
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

1,654
(395)
(388)
(13)

(15)
—
(89)
754

6.17

1,144
(317)
(364)
—

(14)
(651)
74
(128)

5.39

481
(137)
(164)
—

(6)
(434)
102
(158)

5.74

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

436
(76)
(196)
(1)

(6)
(111)
(31)
15

54
(12)
(5)
—

(1)
—
(13)
23

52
(17)
(14)
—

(2)
(96)
35
(42)

10.52

2.40

6.20

The preceding Total and International results of oil and gas producing activities tables exclude $19 million and $28 million in

2002 and 2001, respectively, related to discontinued operations.

B e n e a t h t h e S u r f a c e

Quantities of Oil and Gas Reserves

Set forth below is a summary of the reserves which were evaluated by independent petroleum consultants for each of the years

ended 2003, 2002 and 2001.

2003

2002

2001

PREPARED

AUDITED

PREPARED

AUDITED

PREPARED

AUDITED

Domestic
Canada
International

33%
28%
98%

37%
—%
—%

12%
31%
100%

61%
—%
—%

67%
43%
100%

9%
—%
—%

“Prepared” reserves are those estimates of quantities of reserves which were prepared by an independent petroleum
consultant. “Audited” reserves are those quantities of revenues which were estimated by Devon employees and audited by an
independent petroleum consultant.

The domestic reserves were evaluated by the independent petroleum consultants of LaRoche Petroleum Consultants, Ltd.

and Ryder Scott Company, L.P. in each of the years presented. The Canadian reserves were evaluated by the independent
petroleum consultants of AJM Petroleum Consultants in 2003 and 2002, and Paddock Lindstrom & Associates and Gilbert
Laustsen Jung Associates, Ltd. in 2001. The International reserves were evaluated by the independent petroleum consultants of
Ryder Scott Company, L.P. in each of the years presented.

Set forth below is a summary of the changes in the net quantities of crude oil, natural gas and natural gas liquids reserves

for each of the three years ended December 31, 2003.

Proved reserves as of December 31, 2000

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2001

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003
Proved developed reserves as of:

December 31, 2000
December 31, 2001
December 31, 2002
December 31, 2003

OIL
(MMBBLS)

406
(14)
17
166
(36)
(12)
527
(10)
36
13
(42)
(80)
444
(9)
29
262
(62)
(3)
661

232
298
260
408

GAS
(BCF)

3,045
(284)
499
2,267
(489)
(14)
5,024
(81)
570
1,723
(761)
(639)
5,836
(9)
834
1,650
(863)
(132)
7,316

2,595
3,911
4,618
5,980

TOTAL

NATURAL
GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

50
7
7
52
(8)
—
108
—
11
105
(19)
(13)
192
—
20
19
(22)
—
209

46
88
150
179

963
(54)
107
596
(126)
(14)
1,472
(23)
142
405
(188)
(199)
1,609
(11)
188
556
(228)
(25)
2,089

711
1,038
1,180
1,584

100

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Proved reserves as of December 31, 2000

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2001

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003
Proved developed reserves as of:

December 31, 2000
December 31, 2001
December 31, 2002
December 31, 2003

Proved reserves as of December 31, 2000

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2001

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003
Proved developed reserves as of:

December 31, 2000
December 31, 2001
December 31, 2002
December 31, 2003

DOMESTIC

NATURAL
GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

46
7
5
—
(6)
—
52
2
6
105
(14)
(5)
146
(1)
14
19
(17)
—
161

42
48
117
136

692
(62)
77
43
(95)
(13)
642
15
73
404
(118)
(131)
885
2
111
357
(146)
(22)
1,187

582
546
719
964

CANADA

NATURAL
GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

4
—
2
52
(2)
—
56
(2)
5
—
(5)
(8)
46
1
6
—
(5)
—
48

4
40
33
43

127
(3)
30
535
(29)
—
660
(18)
69
1
(68)
(68)
576
(9)
76
2
(63)
(3)
579

119
485
455
493

GAS
(BCF)

2,521
(262)
360
170
(376)
(14)
2,399
26
344
1,722
(482)
(457)
3,552
57
510
1,474
(589)
(120)
4,884

2,087
1,988
2,802
3,935

GAS
(BCF)

524
(22)
139
2,097
(113)
—
2,625
(107)
226
1
(279)
(182)
2,284
(33)
324
1
(267)
(12)
2,297

508
1,923
1,816
1,964

OIL
(MMBBLS)

226
(25)
12
15
(26)
(11)
191
8
10
12
(24)
(50)
147
(6)
12
92
(31)
(2)
212

192
167
135
171

OIL
(MMBBLS)

36
—
5
133
(8)
—
166
2
26
1
(16)
(30)
149
(4)
16
2
(14)
(1)
148

30
124
119
123

B e n e a t h t h e S u r f a c e

101

Proved reserves as of December 31, 2000

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2001

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions of estimates
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003
Proved developed reserves as of:

December 31, 2000
December 31, 2001
December 31, 2002
December 31, 2003

INTERNATIONAL

OIL
(MMBBLS)

GAS
(BCF)

NATURAL
GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

144
11
—
18
(2)
(1)
170
(20)
—
—
(2)
—
148
1
1
168
(17)
—
301

10
7
6
114

—
—
—
—
—
—
—
—
—
—
—
—
—
(33)
—
175
(7)
—
135

—
—
—
81

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

—
—
—
—

144
11
—
18
(2)
(1)
170
(20)
—
—
(2)
—
148
(4)
1
197
(19)
—
323

10
7
6
127

The preceding International quantities of reserves are attributable to production sharing contracts with various foreign

governments.

The preceding Total and International quantities of oil and gas reserves tables exclude the following proved reserves and

proved developed reserves related to discontinued operations.

Proved reserves as of:
December 31, 2000
December 31, 2001
December 31, 2002

Proved developed reserves as of:

December 31, 2000
December 31, 2001
December 31, 2002

OIL
(MMBBLS)

GAS
(BCF)

NATURAL
GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

53
59
1

29
26
—

413
453
—

35
37
—

12
13
—

—
—
—

134
147
1

35
32
—

102

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Standardized Measure of Discounted Future Net Cash Flows

The accompanying tables reflect the standardized measure of discounted future net cash flows relating to Devon’s interest in

proved reserves:

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

TOTAL
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

60,562

38,399

21,769

(3,693)
(16,232)
(12,078)
28,559
(12,638)
15,921

(2,053)
(9,076)
(8,737)
18,533
(8,168)
10,365

(1,860)
(7,682)
(3,050)
9,177
(4,162)
5,015

DOMESTIC
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

36,602

20,571

(2,028)
(10,788)
(6,848)
16,938
(7,435)
9,503

(1,122)
(5,871)
(3,911)
9,667
(4,157)
5,510

9,861

(793)
(3,774)
(759)
4,535
(1,734)
2,801

CANADA
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

15,517

13,799

(1,051)
(3,585)
(3,316)
7,565
(3,442)
4,123

(633)
(2,600)
(3,999)
6,567
(2,677)
3,890

9,011

(922)
(3,292)
(2,006)
2,791
(1,195)
1,596

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

8,443

(614)
(1,859)
(1,914)
4,056
(1,761)
2,295

4,029

(298)
(605)
(827)
2,299
(1,334)
965

2,897

(145)
(616)
(285)
1,851
(1,233)
618

B e n e a t h t h e S u r f a c e

103

Future cash inflows are computed by applying year-end prices (averaging $27.55 per barrel of oil, adjusted for

transportation and other charges, $5.18 per Mcf of gas and $21.22 per barrel of natural gas liquids at December 31, 2003) to
the year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are
provided by contractual arrangements in existence at year-end.

Future development and production costs are computed by estimating the expenditures to be incurred in developing
and producing proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of
existing economic conditions. Of the $3.7 billion of future development costs, $779 million, $596 million and $285 million are
estimated to be spent in 2004, 2005 and 2006, respectively.

Future production costs include general and administrative expenses directly related to oil and gas producing activities.

Future income tax expenses are computed by applying the appropriate statutory tax rates to the future pre-tax net cash
flows relating to proved reserves, net of the tax basis of the properties involved. The future income tax expenses give effect
to permanent differences and tax credits but do not reflect the impact of future operations.

Future development costs include not only development costs, but also future dismantlement, abandonment and
rehabilitation costs. Included as part of the $3.7 billion of future development costs are $937 million of future dismantlement,
abandonment and rehabilitation costs.

The preceding Total and International standardized measure of discounted future net cash flows tables exclude $21

million and $299 million in 2002 and 2001, respectively, related to discontinued operations.

Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to Devon’s proved

reserves are as follows:

Beginning balance
Sales of oil, gas and natural gas liquids, net of

production costs

Net changes in prices and production costs
Extensions, discoveries and improved recovery, net of

future development costs

Purchase of reserves, net of future development costs
Development costs incurred during the period which

reduced future development costs

Revisions of quantity estimates
Sales of reserves in place
Accretion of discount
Net change in income taxes
Other, primarily changes in timing
Ending balance

YEAR ENDED DECEMBER 31,
2002

2001

2003

(IN MILLIONS)

10,365

5,015

12,065

(4,562)
2,645

2,218
5,763

1,022
(728)
(307)
1,531
(2,305)
279
15,921

(2,402)
9,122

1,471
888

175
(61)
(1,879)
692
(2,673)
17
10,365

(2,126)
(11,878)

582
2,480

314
(316)
(84)
1,708
3,340
(1,070)
5,015

The preceding table excludes $21 million, $299 million and $407 million as of December 31, 2002, 2001 and 2000,

respectively, related to discontinued operations.

104

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Following is a summary of the unaudited interim results of operations for the years ended December 31, 2003,

and 2002.

Oil, gas and natural gas liquids sales
Total revenues
Net earnings before cumulative effect of change

in accounting principle

Net earnings
Net earnings per common share:

Basic:

Net earnings before cumulative effect of

change in accounting principle

Cumulative effect of change in accounting

principle
Total basic

Diluted:

Net earnings before cumulative effect of

change in accounting principle

Cumulative effect of change in accounting

principle

Total diluted

Oil, gas and natural gas liquids sales
Total revenues
Net earnings (loss)
Net earnings (loss) per common share:

Basic
Diluted

FIRST
QUARTER

SECOND
QUARTER

2003
THIRD
QUARTER

FOURTH
QUARTER

FULL
YEAR

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

1,237
1,671

420
436

2.66

0.10
2.76

2.57

0.10
2.67

1,478
1,813

356
356

1.67

—
1.67

1.62

—
1.62

1,613
1,948

412
412

1.76

—
1.76

1.71

—
1.71

1,564
1,921

543
543

2.32

—
2.32

2.25

—
2.25

5,892
7,352

1,731
1,747

8.24

0.08
8.32

8.00

0.07
8.07

FIRST
QUARTER

SECOND
QUARTER

2002
THIRD
QUARTER

FOURTH
QUARTER

FULL
YEAR

(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

743
903
62

0.41
0.40

882
1,149
(104)

(0.68)
(0.68)

766
1,031
62

0.38
0.37

926
1,233
84

0.52
0.52

3,317
4,316
104

0.61
0.61

$
$

$
$
$

$
$

The fourth quarter of 2003 includes a $218 million income tax benefit due to a statutory rate reduction of the Canadian tax

rate. The per share effect of this tax benefit was $0.90. The fourth quarter of 2003 also includes $111 million of reduction of
carrying value of oil and gas properties. The after-tax effect of the reduction in carrying value was $74 million or $0.31 per share.
The second quarter of 2002 includes $651 million of reduction of carrying value of oil and gas properties. The fourth quarter

of 2002 includes $205 million for the impairment of ChevronTexaco Corporation common stock. The after-tax effect of these
expenses was $371 million and $128 million, respectively. The per share effects of these quarterly reductions was $2.37 and
$0.82, respectively.

Oil, gas and natural gas liquids sales for the first, second, third and fourth quarters of 2002 exclude $35 million, $21 million,

$17 million and $7 million, respectively, related to discontinued operations.

B e n e a t h t h e S u r f a c e

105

106

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Directors

JOHN W. NICHOLS, 89, is a co-founder
of Devon. He was named chairman
emeritus in 1999. Nichols was chairman
of the board of directors from the time
Devon began operations in 1971 until
1999. He is a founding partner of
Blackwood & Nichols Co., which put
together the first public oil and gas
drilling fund ever registered with the

PETER J. FLUOR, 56, was appointed
to the board of directors in 2003. Fluor
served as a director of Ocean Energy,
Inc. and its predecessors from 1980 to
2003. He has been chairman and chief
executive officer of Texas Crude Energy
Inc., a private oil and gas company,
since January 2001. From 1997 through
2000, Fluor was president and chief

Securities and Exchange Commission. Nichols is a non-
practicing Certified Public Accountant.

executive officer of Texas Crude Energy Inc. He also serves as
lead independent director of Fluor Corp.

J. LARRY NICHOLS, 61, is a co-
founder of Devon. He was named
chairman of the board of directors in
2000. He has been a director since
1971. He served as president until 2003
and has served as chief executive
officer since 1980. Nichols serves as a
director of Smedvig ASA and Baker
Hughes Inc. He also serves as a director

of the Oklahoma City branch of the Federal Reserve Bank of
Kansas City and several industry trade associations. Nichols has
a Bachelor of Science degree in geology from Princeton Univer-
sity and a law degree from the University of Michigan.

MILTON CARROLL, 53, was appointed
to the board of directors in 2003. Carroll
previously served as a director of Ocean
Energy, Inc. from 1997 to 2003. He was
appointed chairman of the board of
directors of CenterPoint Energy Inc. in
2002. Carroll has served as chairman of
the board and chief executive officer of
Instrument Products Inc. since 1977. He

also serves as chairman of Health Care Service Corp. and is a
director of Texas Eastern Products Pipeline Co. Partners, L.L.C.
and EGL Inc.

THOMAS F. FERGUSON, 67, has
served as a director of Devon since
1982. He is chairman of the Audit
Committee. Ferguson is the managing
director of United Gulf Management
Ltd., a wholly owned subsidiary of
Kuwait Investment Projects Co. KSC.
He has represented Kuwait Investment
Projects Co. on the boards of various

companies in which it invests, including Baltic Transit Bank in
Latvia and Tunis International Bank in Tunisia. Ferguson is a
Canadian qualified Certified General Accountant and was
formerly employed by the Economist Intelligence Unit of London
as a financial consultant.

DAVID M. GAVRIN, 69, is chairman of
the Compensation Committee and has
been a director since 1979. Gavrin has
been a private investor since 1989 and is
currently a director of MetBank Holding
Corp. From 1978 to 1988, he was a
general partner of Windcrest Partners, a
private investment partnership in New
York City. For fourteen years prior to

that, he was an officer of Drexel Burnham Lambert Inc.

MICHAEL E. GELLERT, 72, is chairman
of the Nominating and Governance
Committee and has been a director
since 1971. Gellert has been a general
partner of Windcrest Partners, a private
investment partnership in New York City,
since 1967. From January 1958 until his
retirement in October 1989, Gellert
served in executive capacities with

Drexel Burnham Lambert Inc. and its predecessors in New York
City. In addition to serving as a member of Devon's board of
directors, Gellert also serves on the boards of Humana Inc.,
Seacor Smit Inc., Six Flags Inc., Travelers Series Fund Inc., Dalet
Technologies and Smith Barney World Funds.

JOHN A. HILL, 62, was elected to the
board of directors in 2000. Hill has been
with First Reserve Corp., an oil and gas
investment management company,
since 1983 and is currently its vice
chairman and managing director. Prior
to joining First Reserve Corp., Hill was
president, chief executive officer and
director of Marsh & McLennan Asset

Management Co. and served as the deputy administrator of the
Federal Energy Administration during the Ford Administration. Hill
is chairman of the board of trustees of the Putnam Funds in
Boston, a trustee of Sarah Lawrence College and a director of
TransMontaigne Inc., various companies controlled by First
Reserve Corp. and Continuum Health Partners.

B e n e a t h t h e S u r f a c e

107

J. TODD MITCHELL, 45, was
appointed to the board of directors in
2002. He served on the board of
directors of Mitchell Energy & Develop-
ment Corp. from 1993 to 2002. He has
served as president of GPM Inc., a
family-owned investment company,
since 1998. Mitchell also has served as
president of Dolomite Resources Inc., a

privately owned mineral exploration and investments company,
since 1987. Additionally, he has been chairman of Rock Solid
Images, a privately owned seismic data analysis software
company, since 1998.

ROBERT A. MOSBACHER JR., 52,
was appointed to the board of directors
in 1992. He has served as president and
chief executive officer of Mosbacher
Energy Co. since 1986. He was
previously a director of PennzEnergy
Co. and served on its Executive
Committee. Mosbacher is currently a
director of JPMorgan Chase & Co.,

Houston Regional Board and is on the executive committee of
the U.S. Oil & Gas Association.

ROBERT L. HOWARD, 67, was
appointed to the board of directors in
2003. Howard served as a director of
Ocean Energy, Inc. from 1996 to 2003.
Howard retired in 1995 from his position
as vice president of Domestic
Operations, Exploration and Production,
of Shell Oil Co. He is also a director of
Southwestern Energy Co. and

McDermott International Inc.

WILLIAM J. JOHNSON, 69, was
elected to the board of directors in
1999. Johnson has been a private
consultant for the oil and gas industry
for more than five years. He is president
and a director of JonLoc Inc., an oil and
gas company of which he and his family
are the only stockholders. Johnson has
served as a director of Tesoro Petroleum

Corp. since 1996. From 1991 to 1994, Johnson was president,
chief operating officer and a director of Apache Corp.

MICHAEL M. KANOVSKY, 55, was a
co-founder of Northstar Energy Corp.,
which was acquired by Devon in 1998.
He served on Northstar's board of
directors since 1982. He is president of
Sky Energy Corp., a privately held
energy corporation. Kanovsky continues
to be active in the Canadian energy
industry and is currently a director of

ARC Resources Ltd. and Bonavista Petroleum Ltd.

CHARLES F. MITCHELL, 55, was
appointed to the board of directors in
2003 upon completion of the merger
with Ocean Energy. Mitchell served as a
director of Ocean Energy, Inc. from 1995
to 2003. He is a physician and surgeon
and has been a senior partner of ENT
Medical Center in Baton Rouge, La.,
since 1985. Mitchell is involved in

numerous private investments.

108

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Senior Officers

JOHN RICHELS, 52, was elected
president of Devon in 2004. He
previously served as a senior vice
president of Devon and president and
chief executive officer of Devon's
Canadian subsidiary. Richels joined
Devon through its 1998 acquisition of
Canadian-based Northstar Energy
Corp., where he held the position of

the law firm of Mayer, Brown & Platt (now Mayer, Brown, Rowe &
Maw) in New York City. In addition, he was a senior vice
president and managing director for investment banking at
Bankers Trust Co. in New York City for 10 years. Ligon also
served for three years in various positions with the U.S. Depart-
ments of the Interior and Treasury as well as the Department of
Energy. Ligon holds an undergraduate degree in chemistry from
Westminster College and a law degree from the University of
Texas School of Law.

MARIAN J. MOON, 53, was elected
to the position of senior vice
president, Administration in 1999.
Moon is responsible for Human
Resources, Office Administration,
Information Technology, Process
Development and Corporate
Governance. Moon has been with
Devon for 19 years in various capaci-

ties, including manager of Corporate Finance and Corporate
Secretary. Prior to joining Devon, Moon was employed for 11
years by Amarex Inc., an Oklahoma City-based oil and natural
gas production and exploration firm. Her last position with
Amarex was treasurer. Moon is a member of the American
Society of Corporate Secretaries. She is a graduate of Valparaiso
University.

DARRYL G. SMETTE, 56, was
elected to the position of senior vice
president, Marketing and Midstream,
in 1999. Smette previously held the
position of vice president, Marketing
and Administrative Planning, since
1989. He joined Devon in 1986 as
manager of Gas Marketing. His
marketing background includes 15

years with Energy Reserves Group Inc./BHP Petroleum
(Americas) Inc. He last served as director of marketing with
Energy Reserves Group/BHP. Smette is also an oil and gas
industry instructor, approved by the University of Texas Depart-
ment of Continuing Education. Smette is a member of the
Oklahoma Independent Producers Association, Natural Gas
Association of Oklahoma and the American Gas Association. He
holds an undergraduate degree from Minot State University and
a master's degree from Wichita State University.

executive vice president and chief financial officer from 1996 to
1998 and served on the board of directors from 1993 to 1996.
Prior to joining Northstar, Richels was managing partner, chief
operating partner and a member of the executive committee of
the Canadian based national law firm, Bennett Jones. Richels
previously served as a director of a number of publicly traded
companies and is a former vice-chairman of the board of
governors of the Canadian Association of Petroleum Producers.
He holds a bachelor's degree in economics from York University
and a law degree from the University of Windsor. While employed
by Bennett Jones in the 1980s, Richels served as general
counsel of the XV Olympic Winter Games Organizing Committee
in Calgary.

BRIAN J. JENNINGS, 43, was
appointed chief financial officer effective
March 31, 2004, and elected to the
position of senior vice president,
Corporate Finance and Development, in
2002. Jennings joined Devon in March
2000 as vice president, Corporate
Finance. Prior to joining Devon,
Jennings was a managing director in the

Energy Investment Banking Group of PaineWebber Inc. He
began his banking career at Kidder, Peabody in 1989 before
moving to Lehman Brothers in 1992 and later to PaineWebber in
1997. Jennings specialized in providing strategic advisory and
corporate finance services to public and private companies in
the exploration and production and oilfield service sectors. He
began his energy career with ARCO International Oil & Gas, a
subsidiary of Atlantic Richfield Co. Jennings received his
Bachelor of Science in petroleum engineering from the University
of Texas at Austin and his Master of Business Administration
from the University of Chicago's Graduate School of Business.

DUKE R. LIGON, 62, was elected to the
position of senior vice president and
general counsel in 1999. Ligon joined
Devon as vice president and general
counsel in 1997. In addition to Ligon's
primary role of managing Devon's
corporate legal matters (including litiga-
tion), he has direct involvement with the
company's governmental affairs and its

merger and acquisition activities. Prior to joining Devon, Ligon
practiced energy law for 12 years and last served as a partner at

B e n e a t h t h e S u r f a c e

109

Glossary of Terms

British thermal unit (Btu): A measure of heat
value. An Mcf of natural gas is roughly equal to
one million Btu.

Block: Refers to a contiguous leasehold
position. In federal offshore waters, a block is
typically 5,000 acres.

Coalbed natural gas: An unconventional gas
resource that is present in certain coal deposits.

Deepwater: In offshore areas, water depths of
greater than 600 feet.

Development well: A well drilled within the area
of an oil or gas reservoir known to be produc-
tive. Development wells are relatively low risk.

Dry hole: A well found to be incapable of
producing oil or gas in sufficient quantities to
justify completion.

Exploitation: Various methods of optimizing oil
and gas production or establishing additional
reserves from producing properties through
additional drilling or the application of new
technology.

Natural gas liquids (NGLs): Liquid hydrocar-
bons that are extracted and separated from the
natural gas stream. NGL products include
ethane, propane, butane and natural gasoline.

Net acres: Gross acres multiplied by one’s
fractional working interest in the property.

Pilot program: A small-scale test project used
to assess the viability of a concept prior to
committing significant capital to a large-scale
project.

Production: Natural resources, such as oil or
gas, taken out of the ground.
- Gross production: Total production before
deducting royalties.
- Net production: Gross production, minus
royalties, multiplied by one’s fractional working
interest.

Proppant: Granular particles mixed with the
fracturing fluid to hold open the formation
cracks created by a fracture treatment.

Prospect: An area designated for the potential
drilling of development or exploratory wells.

Exploratory well: A well drilled in an unproved
area, either to find a new oil or gas reservoir or
to extend a known reservoir. Sometimes referred
to as a wildcat.

Proved reserves: Estimates of oil, gas and NGL
quantities thought to be recoverable from
known reservoirs under existing economic and
operating conditions.

Field: A geographical area under which one or
more oil or gas reservoirs lie.

Floating production, storage and offloading
unit (FPSO): A moored tanker-type vessel used
to develop an offshore oil field. Oil is stored
within the FPSO until offloaded to a tanker for
transportation to a terminal or refinery.

Formation: An identifiable layer of rocks named
after its geographical location and dominant
rock type.

Fracture, refracture: The process of applying
hydraulic pressure to an oil or gas bearing
geological formation to crack the formation and
stimulate the release of oil and gas.

Gross acres: The total number of acres in
which one owns a working interest.

Heavy oil: Dense, viscous crude that often
requires the application of heat to enable it to
flow to the surface.

Increased density/infill: A well drilled in
addition to the number of wells permitted under
initial spacing regulations, used to enhance or
accelerate recovery, or prevent the loss of
proved reserves.

Independent producer: A non-integrated oil
and gas producer with no refining or retail
marketing operations.

Lease: A legal contract that specifies the terms
of the business relationship between an energy
company and a landowner or mineral rights
holder on a particular tract.

Recavitate: The process of applying pressure
surges on the coal formation at the bottom of a
well in order to increase fracturing, enlarge the
bottomhole cavity and thereby increase gas
production.

Recompletion: The modification of an existing
well for the purpose of producing oil or gas from
a different producing formation.

Reservoir: A rock formation or trap containing
oil and/or natural gas.

Royalty: The landowner’s share of the value of
minerals (oil and gas) produced on the property.

SEC Case: The method for calculating future
net revenues from proved reserves as
established by the Securities and Exchange
Commission (SEC). Future oil and gas revenues
are estimated using essentially fixed or unesca-
lated prices. Future production and develop-
ment costs also are unescalated and are
subtracted from future revenues.

SEC @ 10% or SEC 10% present value: The
future net revenue anticipated from proved
reserves using the SEC Case, discounted at
10%.

Seismic: A tool for identifying underground
accumulations of oil or gas by sending energy
waves or sound waves into the earth and
recording the wave reflections. Results indicate
the type, size, shape and depth of subsurface
rock formations. 2-D seismic provides two-
dimensional information while 3-D creates three-
dimensional pictures. 4-C, or four-component,
seismic is a developing technology that utilizes
measurement and interpretation of shear wave
data. 4-C seismic improves the resolution of
seismic images below shallow gas deposits.

110

D e v o n E n e r g y 2 0 0 3 A n n u a l R e p o r t

Steam-assisted gravity drainage (SAGD): A
method of producing heavy oil from oil sands by
injecting steam underground. The heated heavy
oil drains into a second horizontal producing
well located directly below the steam injection
well.

Stepout well: A well drilled just outside the
proved area of an oil or gas reservoir in an
attempt to extend the known boundaries of the
reservoir.

Undeveloped acreage: Lease acreage on
which wells have not been drilled or completed
to a point that would permit the production of
commercial quantities of oil or gas.

Unit: A contiguous parcel of land deemed to
cover one or more common reservoirs, as
determined by state or federal regulations. Unit
interest owners generally share proportionately
in costs and revenues.

Waterflood: A method of increasing oil
recoveries from an existing reservoir. Water is
injected through a special “water injection well”
into an oil producing formation to force
additional oil out of the reservoir rock and into
nearby oil wells.

Working interest: The cost-bearing ownership
share of an oil or gas lease.

Workover: The process of conducting remedial
work, such as cleaning out a well bore, to
increase or restore production.

VOLUME ACRONYMS

Bbl: A standard oil measurement that equals
one barrel (42 U.S. gallons)
- MBbl: One thousand barrels
- MMBbl: One million barrels

BOD: Barrels of oil per day

Mcf: A standard measurement unit for volumes
of natural gas that equals one thousand cubic
feet.
- MMcf: One million cubic feet
- Bcf: One billion cubic feet

MMcfd: Millions of cubic feet of gas per day

Boe: A method of equating oil, gas and natural
gas liquids. Gas is converted to oil based on its
relative energy content at the rate of six Mcf of
gas to one barrel of oil. NGLs are converted
based upon volume: one barrel of natural gas
liquids equals one barrel of oil.
- MBoe: One thousand barrels of oil
equivalent
- MMBoe: One million barrels of oil
equivalent

Common Stock Trading Data

QUARTER

HIGH

LOW

LAST

VOLUME

2002
First
Second
Third
Fourth

2003
First
Second
Third
Fourth

$ 49.10
$ 52.28
$ 49.70
$ 53.10

$ 50.37
$ 56.65
$ 53.48
$ 58.80

$ 34.40
$ 45.05
$ 33.87
$ 42.14

$ 42.45
$ 45.25
$ 46.38
$ 45.90

$ 48.77
$ 49.28
$ 48.25
$ 45.90

$ 48.22
$ 53.40
$ 48.19
$ 57.26

70,651,200
62,348,000
67,042,000
71,894,800

88,372,000
107,345,700
92,719,100
88,739,086

Investor Information

Northstar Exchangeable Shareholders

CIBC Mellon Trust Company
P.O. Box 1036
Adelaide Street Postal Station
Toronto, Ontario M5C 2K4
Toll Free: (800) 387-0825

COMPANY CONTACTS

Vince White, Vice President
Communications and Investor Relations
Telephone: (405) 552-4505
E-mail: vince.white@dvn.com

Investor Relations:
Zack Hager
Manager Investor Relations
Telephone: (405) 552-4526
E-mail: zack.hager@dvn.com

Scott Smalling
Senior Investor Relations Analyst
Telephone: (405) 228-4477
E-mail: scott.smalling@dvn.com

Shea Snyder
Senior Investor Relations Analyst
Telephone: (405) 552-4782
E-mail: shea.snyder@dvn.com

Media:

Brian Engel
Manager Public Affairs
Telephone: (405) 228-7750
E-mail: brian.engel@dvn.com

Chip Minty
Senior External Communications Specialist
Telephone: (405) 228-8647
E-mail: chip.minty@dvn.com

PUBLICATIONS
A copy of Devon’s annual report to the
Securities and Exchange Commission (Form
10-K) and other publications are available at no
charge upon request. Direct requests to:

Judy Roberts
Telephone: (405) 552-4570
Fax: (405) 552-7818
E-mail: judy.roberts@dvn.com

ANNUAL MEETING
Our annual shareholders’ meeting will be held
at 8 a.m. Central Time on Tuesday, June 8,
2004, in the Kingkade Room, Second Floor of
The Renaissance Hotel, 10 North Broadway,
Oklahoma City, OK.

INDEPENDENT AUDITORS
KPMG LLP
Oklahoma City, OK

STOCK TRADING DATA
Devon Energy Corporation’s common stock is
traded on the American Stock Exchange
(symbol: DVN). There are approximately 22,000
shareholders of record.

The Northstar exchangeable shares are traded
on The Toronto Stock Exchange (symbol: NSX).
They are exchangeable on a one-for-one basis
for Devon common stock. The exchangeable
shares also qualify as a domestic Canadian
investment for Canadian institutional holders
and have the same rights as Devon common
stock.

DEVON’S WEBSITE
To learn more about Devon Energy, visit our
website at: www.devonenergy.com.
Devon’s website contains press releases,
SEC filings, answers to commonly asked
questions, stock quote information and
more.

CORPORATE HEADQUARTERS
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260
Telephone: (405) 235-3611
Fax: (405) 552-4550

PERMIAN, MID-CONTINENT,
ROCKY MOUNTAINS and
MARKETING AND MIDSTREAM OPERATIONS
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260

GULF and INTERNATIONAL OPERATIONS
Devon Energy Corporation
Devon Energy Tower
1200 Smith Street
Houston, TX 77002-4313
Telephone: (713) 286-5700

GULF COAST OPERATIONS
Devon Energy Corporation
3 Allen Center
333 Clay Street
Houston, TX 77002-4000
Telephone: (713) 286-5700

CANADIAN OPERATIONS
Devon Canada Corporation
2000, 400 - 3rd Avenue S.W.
Calgary, Alberta T2P 4H2
Telephone: (403) 232-7100

SHAREHOLDER ASSISTANCE
For information about transfer or exchange of
shares, dividends, address changes, account
consolidation, multiple mailings, lost certifi-
cates and Form 1099:

Devon Energy Common Shareholders

Wachovia Bank, N.A.
Shareholder Services Group
1525 West W.T. Harris Blvd.
Bldg. 3C, 3rd Floor
Charlotte, NC 28288-1153
Toll Free: (800) 829-8432

B e n e a t h t h e S u r f a c e

111

Beneath the Surface

D E V O N E N E R G Y C O R P O R AT I O N
20 North Broadway
Oklahoma City, OK 73102-8260
Telephone (405) 235-3611 Fax (405) 552-4550
www.devonenergy.com