Devon Energy Annual Report 2004

FY2004 Annual Report · Devon Energy

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SPECIAL
O PER ATIO N M A P
IN SERT
A REA S OF

2 0 0 4 A N N U A L R E P O R T

DEVON
DEVON
ENERGY
ENERGY

DISCOVERING
DISCOVERING
DEVON
DEVON

Insight Management’s Q&A PG 6 Discovering Our Full Potential Portfolio of Properties PG 8
Insight Management’s Q&A PG 6 Discovering Our Full Potential Portfolio of Properties PG 8
Touching Lives Community and Environmental Stewardship PG 18
Touching Lives Community and Environmental Stewardship PG 18

About this Issue
D

iscovering Devon is our 2004 Annual
Report. Inside, our Chairman and CEO,
Larry Nichols, summarizes 2004 and his view of
our future. You also will see facts, figures and
charts about Devon’s performance last year with
comparisons to previous years. We have included
descriptions of many of our oil and gas projects
and examples of our contributions to the commu-
nities where we do business. You will also find
financial statements, detailed notes explaining
them and the report of our auditors. All of this is
typical content for an annual report.

This annual report was designed, however,

to look and feel like a magazine—a magazine of

discovery. The theme, Discovering Devon, was
selected from about 1,000 employee submissions.
Cab Craig, an engineer in Devon’s Gulf Division
in Houston, submitted the winning theme.

Please take a few minutes to page
through this report. In keeping with its theme of
discovery, this book is intended to help you
discover something new about Devon. We are
excited about our company and our accomplish-
ments. And we are proud of our values and our
employees who live them. That pride is reflected
within the pages of this report. We hope you
enjoy it.

Just as discovery is the aim of exploratory drilling, our aim with
this annual report is to lead you in a discovery of Devon.

C O N T E N T S

F E A T U R E S

Insight Members of management answer questions providing
insight into Devon’s strategy and outlook.

Discovering Our Full Potential Devon provides an in-depth
view of its portfolio of producing properties.

Touching Lives Devon’s community involvement, environmental
stewardship and attention to employee safety reflect the company’s
core values.

Special Insert

Devon provides an Areas of Operation map and Key Property
Highlights. (between pages 16 and 17)

In the above photo, Devon employees Tim Raley (left) and George Jackson bring
the message of oilfield safety to high school students in Bridgeport, Texas.

Touching Lives — PG 18

D E P A R T M E N T S

Five-Year Highlights 3
Letter to Shareholders 4
11-Year Property Data 14
Index to Financials 25
Directors & Officers 103
Glossary of Terms 106

C O V E R

Much of the earth’s undiscovered
oil and gas reserves are believed
to lie beneath its oceans. This
offshore rig is at work in the
Gulf of Mexico.

M I S S I O N

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

V O N

E N E

C O R

P O R A T

I O N

D I S C O V E R I N G D E V O N

B R I E F H I S T O R Y

Historic Highlights

This 1875 photograph of a
Pennsylvania oil field is from
the archives of PennzEnergy,
acquired by Devon in 1999.

2005

2000

1995

2004 – Devon’s stock price hits all-time high.

– Devon initiates $1.5 billion non-core property divestiture program and begins repurchasing up to 10%

of its common stock.

– Devon declares a two-for-one stock split and transfers its common stock listing to the New York Stock Exchange.
– Quarterly cash dividend increased to five cents per common share.

2003 – Devon’s $5.3 billion merger with Ocean Energy creates the largest U.S.-based independent oil and gas

producer with 4,000 employees worldwide.

2002 – Devon acquires Mitchell Energy for $3.5 billion, adding the prolific Barnett Shale play in north Texas to its
core assets and establishing the company as a leading independent processor of natural gas and
natural gas liquids.

– Devon named to the Fortune 500.

2001 – Acquisition of Anderson Exploration for $4.6 billion positions Devon as the third-largest independent

1990

gas producer in Canada.

– Devon combines its marketing and midstream operations creating a new division.

2000 – Devon merges with Santa Fe Snyder creating a top five U.S.-based independent. The $3.5 billion

transaction expands Devon’s international presence.

– President and CEO Larry Nichols named Chairman of the Board.
– Devon named to S&P 500 Index.

1999 – The $2.6 billion acquisition of PennzEnergy establishes Devon as a significant offshore Gulf of Mexico operator.

– Employee count reaches 1,500 worldwide.

1998 – Devon acquires Northstar Energy for $750 million, creating a top 15 U.S.-based independent.
1996 – Devon acquires Kerr-McGee’s North American onshore oil and gas properties for $250 million, increasing

the company’s reserves by 46%.

– Quarterly cash dividend increased to 2.5 cents per common share.

1993 – Devon declares its first quarterly cash dividend of 1.5 cents per common share.
1992 – Acquisition of Hondo Oil & Gas for $122 million sets the stage for a series of major acquisitions in the

years to come.

1989 – Devon begins production of coalbed natural gas in the San Juan Basin.
1988 – Devon becomes a public company, listing on the American Stock Exchange under the ticker symbol DVN.
1981 – Devon, with 185 employees, relocates corporate headquarters to present downtown Oklahoma City location.

1971 – Devon founded by John Nichols and his son Larry.

1950 – Devon co-founder, John Nichols, creates the first public oil and gas drilling fund registered with the

Securities and Exchange Commission.

1985

1980

1975

1970

1965

1950

2 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

2 0 0 4

A N N U A L R E P O R T

DEVON
ENERGY

COMPANY PROFILE Devon is
engaged in oil and gas exploration,
production and property acquisi-
tions. 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 select international
areas. Devon is included in the S&P
500 Index and its common shares
trade on the New York 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-look-
ing statements” as defined by the Securities
and Exchange Commission. Such statements
are those concerning Devon’s plans, expec-
tations and objectives for future operations,
including reserve potential 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 for-
ward-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
“Management’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.

Five-Year Highlights

Year Ended December 31,

2000

2001

2002

2003

2004

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

Total revenues (2)
Operating costs and expenses
Earnings from operations

Other expenses
Total income tax expense (benefit)

Net earnings from continuing operations

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

Net earnings
Preferred stock dividends

Net earnings applicable to common stockholders

Net earnings per share:

Basic
Diluted

Weighted average common shares outstanding:

Basic
Diluted

Cash flows from continuing operating activities
Operating cash flows 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)
NGLs (MMBbls)

Oil, Gas and NGLs (MMBoe) (5)

2,587
1,431
1,156

2,864
2,672
192

118
377
661

69
—

730
10
720

164
5
23

31
49

103
10
93

4,316
3,775
541

675
(193)
59

45
—

104
10
94

7,352
4,710
2,642

397
514
1,731

—
16

1,747
10
1,737

9,189
5,485
3,704

411
1,107
2,186

—
—

2,186
10
2,176

2.83
2.75

0.37
0.36

0.31
0.30

4.16
4.04

4.51
4.38

255
263

1,479
110
1,589

255
259

1,776
134
1,910

309
313

1,726
28
1,754

417
433

3,768
—
3,768

482
499

4,816
—
4,816

LAST YEAR
CHANGE

25%
16%
40%

3%
115%
26%

NM
NM

25%
—
25%

8%
8%

16%
15%

28%
NM
28%

0.09

0.10

0.20

100%

2000

2001

2002

2003

2004

LAST YEAR
CHANGE

6,860

13,184

16,225

27,162

29,736

760
1,289
3,277
251

406
3,045
50
963

649
5,940
3,259
435

527
5,024
108
1,472

662
6,900
4,653
22

677
7,903
11,056
293

692
6,339
13,674
483

2%
(20%)
24%
65%

444
5,836
192
1,609

661
7,316
209
2,089

596
7,494
232
2,077

(10%)
2%
11%
(1%)

LAST YEAR
CHANGE

$
$

$
$
$
$

Year Ended December 31,

2000

2001

2002

2003

2004

Production (Net of royalties)

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

Oil, Gas and NGLs (MMBoe) (5)

37
417
7
113

36
489
8
126

42
761
19
188

62
863
22
228

78
891
24
251

26%
3%
10%
10%

(1) Years 2000 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 continuing operations since 2003. Data for 2000 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 11 and one-fourth months attributable to the Mitchell merger and in 2001, include only two and one-half months attributable to the Anderson acquisition.
All periods have been adjusted to reflect the two-for-one stock split that occurred on November 15, 2004.
Excludes other income, which is netted against other expense.
The cash dividend per share presented for 2000 is not representative of the actual amount paid by Devon because of the Santa Fe Snyder merger accounted for as a pooling-of-interests.
For the year 2000, Devon paid cash dividends of $0.10 per share.

(2)
(3)

(4) Debentures exchangeable into 14.2 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.

D I S C O V E R I N G D E V O N

L E T T E R T O S H A R E H O L D E R S

Dear Fellow Shareholders:

For Devon Energy Corporation, 2004 was a year of outstanding achieve-
ment. As demonstrated by these key financial and operating metrics, the
company delivered yet another record-breaking performance:

• Net earnings climbed to $2.2 billion, or $4.38 per share,

an all-time record.

• Total revenues soared to $9.2 billion, up 25% over our

previous record set in 2003.

• Cash flow from operations grew 28% over 2003,

to $4.8 billion, also an all-time record.

• Oil, gas and natural gas liquids production climbed 10%,

to a record 251 million equivalent barrels.

• With drill-bit capital expenditures of $2.8 billion, we added

313 million barrels of oil and gas reserves through
discoveries, extensions and performance revisions.

Devon’s 2004 financial performance allowed us to
fully fund a robust capital program while simultaneously
strengthening our balance sheet. We funded total capital
expenditures of $3.1 billion, repaid almost $1 billion in
debt and increased our cash and short-term investments to
$2.1 billion at year-end. By the end of 2004, we had pro-
vided for all debt maturities through 2007. Furthermore,
Devon’s net debt to adjusted capitalization ratio declined
during the year to a comfortable 27%.

Yes, the key metrics reflect that 2004 was the best
year in Devon’s history. And yet, one must look beyond
these numbers to discover many of the year’s most
important achievements.

During 2004, we began to reap the rewards of our
long-term value creation strategy. Devon’s foundation of
high-quality North American oil and gas assets delivered
profitable production and reserve additions. Onshore, in
North America, we drilled 2,089 oil and gas wells with a
97% success rate. We increased production organically
and added more oil and gas reserves than we produced.

In addition to funding the projects that delivered

our 2004 reserves and production growth, our core
North American properties generated significant quanti-
ties of excess cash. This excess cash allowed us to make
significant long-term investments as well. After years of
investing in these longer-term projects, we are now
beginning to realize the benefits. In late 2004, we
received regulatory approval for our Jackfish thermal
heavy oil project in Alberta. We expect to begin booking

4 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

LARRY NICHOLS
Chairman and CEO

oil reserves from Jackfish in 2005 and to see first produc-
tion in 2007. When fully operational in 2008, this 100%
Devon-owned project is expected to deliver 35,000 bar-
rels of oil per day, without decline, for more than 20
years. Also during 2004, we made our third discovery in
the emerging lower Tertiary play in the deepwater Gulf
of Mexico. In 2005, we plan to delineate these discover-
ies and to continue to explore for new ones. In addition,
we expect to test several high-impact prospects off the
coast of West Africa this year. These wells are the culmi-
nation of years of preparatory work.

Such long-term investments hold the promise to
deliver significant additions of oil and gas reserves and
production well into the next decade. While the first
cash outlays were made years in advance of any possible
contribution to production or earnings, these invest-
ments captured significant value. They underscore our
commitment to manage Devon to achieve sustainable
success over the long run.

Devon’s commitment to long-term value creation is
also reflected in recent decisions to upgrade our asset base.
Since 2002, we have divested $330 million of non-core
midstream assets. And in late 2004, we announced the
decision to divest non-core oil and gas properties represent-

ing about 15% of our 2004 production. This decision was
a result of our disciplined, fact-based approach to strategic
planning. Throughout our history, we have periodically
purged properties that no longer fit our portfolio. The sale
of these non-core properties and the redeployment of the
capital enhances our ability to create value over a longer
time horizon. Following the divestitures, our efforts will be
focused on a property base with lower operating costs, bet-
ter capital efficiency and greater growth potential.

Another 2004 accomplishment not reflected in the

numbers is the realignment and reinforcement of our sen-
ior management team. In July 2004, Steve Hadden joined
the company as senior vice president of exploration and
production. He brings to Devon more than two decades of
industry management experience. His influence on our
operations is already being felt as Steve focuses his technical
teams on creating incremental value throughout the explo-
ration and production cycle.

Steve’s hiring followed two other senior management

changes in early 2004. John Richels, previously head of
Devon’s Canadian Division, relocated to Oklahoma City
after being named Devon’s president. Brian Jennings, senior
vice president, assumed the additional responsibilities of
chief financial officer.

Perhaps Devon’s greatest accomplishment through-
out our history has been the preservation of our culture.
While we have grown into a sizeable company, with

Oil, Gas and NGLs
Production
(MMBoe*)

Total Revenues
($ Billions)

Earnings
per Share
($ Diluted)

1
5
2

8
2
2

8
8
1

6
2
1

3
1
1

3
.
4

9
.
6 2
.
2

2
.
9

4
.
7

8
3
.
4 4
0
.
4

5
7
.
2

6
3
.
0

0
3
.
0

00 01 02 03 04

…driving revenues
to a record $9.2
billion…

…and earnings per
share to the high-
est level in Devon’s
history.

Production of oil,
gas and NGLs
climbed to a record
251 million equiva-
lent barrels...

* Gas converted to oil
equivalent at the ratio
of 6Mcf:1Bbl.

“large-company” assets, we have maintained a small com-
pany culture. We are relatively free of the politics, red tape
and bureaucracy that can endanger the spirit of a large
organization. And we continue to approach our business
with the freedom to be creative and the power of teamwork.

As I look forward to 2005 and beyond, I see a future

even brighter than our past. The world has entered a period
where oil and gas are becoming increasingly scarce and
valuable commodities. Devon is positioned to benefit from
this environment with a large and profitable North
American production base that provides dependable
reserves and production growth. We are fortunate to have
assembled an inventory of large-scale development projects
that will provide low-risk growth opportunities through the
remainder of this decade. This stable base is complemented
by a dynamic, risk-balanced exploration program that pro-
vides exposure to some of the highest potential areas in the
world. And we have the technical, financial and human
resources to compete anywhere we choose.

During the first half of 2005, we expect to realize
about $1.5 billion in after-tax proceeds from our property
divestitures. In addition, assuming oil and gas prices remain
relatively strong, we will generate cash flow far in excess of
our 2005 capital demands. We are committed to using these
funds to generate incremental value per share. We can
accomplish this through stock repurchases, debt reduction,
dividends and incremental investments. We recognize that
our asset divestiture program will reduce near-term produc-
tion and earnings. However, we are confident our sharehold-
ers will ultimately be rewarded for our focus on optimizing
net value per share over the longer term. Furthermore, we
are convinced that our collective patience will be well
rewarded as Devon’s existing project inventory delivers sig-
nificant top-line production growth over the coming years.
The theme of this 2004 annual report is Discovering
Devon. The balance of the publication offers glimpses into
the properties, the people, the strategies and the values that
define our company. I invite you to explore these pages in
order to know us better. I invite you to Discover Devon.

J. LARRY NICHOLS

Chairman and Chief Executive Officer

March 11, 2005

D I S C O V E R I N G D E V O N

INSIGHT

Devon added significant new
reserves with the drill-bit at a
low unit cost in 2004. Can we
expect Devon to repeat this per-
formance in the future?

JOHN RICHELS:
Yes, we are pleased
with our drilling
results in 2004
and are confident
we will deliver
attractive results in
the future. Devon has invested heavily
for several years to assemble a high-
impact, risk-balanced exploration port-
folio. This portfolio has been con-
structed to provide consistent, economic
results in the future. The positive
impact of these long cycle-time projects
coupled with repeatable growth from
Devon’s core North American onshore
assets, should allow us to continue to
grow our reserve base with attractive
unit costs.

Although drilling program results
can vary considerably from one year to
the next, multi-year results should
reflect the program’s true performance.
We are confident Devon’s balanced
approach of combining low-risk, near-
term projects with high-impact explo-
ration will deliver competitive results
over the long run.

When can we expect to see reserve
additions and oil production from
your lower Tertiary discoveries in
the Walker Ridge area of the deep-
water Gulf of Mexico?

With the energy industry’s current
strength, there is increasing
competition among companies to
attract and retain employees.
How is Devon responding to this
competition?

STEVE HADDEN:
Devon has
announced three
discoveries in the
Walker Ridge area.
The Cascade, St.
Malo and Jack dis-
coveries are all in water depths greater
than 7,000 feet and each is more than
100 miles from land. The development
of these discoveries in such remote and
inhospitable environments clearly
requires a great deal of advance planning
and capital investment. Deepwater tech-
nology is advancing rapidly, enabling us
to consider a variety of development
options for these discoveries. We have
begun preliminary engineering but still
require more information prior to com-
mitting to a development plan.

In 2005, we plan to drill delineation

wells on each of these three discoveries.
We may also conduct a production test
to obtain additional information. Such a
test would require drilling and complet-
ing a well and producing oil from it for
a sustained period. Sustained tests are
difficult and costly in deep water, but
we believe a test is justified given the
significance of these projects. Reserve
bookings could follow a successful
production test in a matter of a few
months. Depending on the develop-
ment option selected, construction
would probably require two or three
additional years prior to first produc-
tion.

MARIAN MOON:
As Devon grew
through mergers
and acquisitions,
we retained the
best elements of
the acquired com-
panies’ employee benefits and retention
programs. Consequently, we offer
industry-leading working conditions
and benefits to our personnel. These
programs include competitive long-term
incentives that reward employees for
their continued commitment to Devon.
We also invest heavily in continuing
education and training programs that
enable employees to refresh and
upgrade their skills and to position
themselves for advancement.

In the future, the oil and gas indus-

try will be challenged by the lack of an
adequate pool of prospective employees
with petroleum industry related degrees.
Devon has made a strong commitment
to meet that challenge by investing in
higher education. In 2004 and early
2005, the company made significant
financial commitments to higher educa-
tion. These gifts will fund teaching and
research facilities in Devon’s name. Also
in 2004, we enhanced our college
internship and recruiting programs tar-
geting promising students as potential
employees. We believe these invest-
ments will encourage young people to
pursue oil and gas careers and to con-
sider Devon for employment upon
graduation.

6 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Members of Devon’s management answer your questions
to provide insight into our strategy.

The company has committed to
repurchase about 10% of its
common stock. Why did you
choose this use of cash rather than
increasing exploration and devel-
opment expenditures?

2004 was the first year in many
that Devon did not complete a
significant merger or acquisition.
Is Devon out of the M&A market
permanently?

BRIAN JENNINGS:
Devon’s number
one objective is to
maximize value
per share. We con-
tinuously evaluate
investment alter-
natives and select the mix that we
believe will best achieve this objective.
Repurchasing stock is but one such
alternative. We have not selected it to
the detriment of our exploration and
development programs. We are funding
our capital programs at optimum levels
while utilizing the excess cash to con-
currently repurchase stock, reduce debt
and pay cash dividends.

Share repurchases can also have
certain advantages over other invest-
ment alternatives. Reducing the num-
ber of outstanding shares increases
every stockholder’s share of ownership
in the company. Furthermore, when
repurchasing Devon’s shares, we are
investing in our own high-quality asset
base. This has definite advantages
because we know and understand these
assets, and we incur no integration
risks or costs.

DUKE LIGON:
Mergers and
acquisitions have
played an impor-
tant role in
Devon’s dramatic
growth since
going public in 1988. However, as evi-
denced by our willingness to periodi-
cally divest producing properties,
growth for growth’s sake was never our
goal. We believed that we could take
advantage of this period of rapid indus-
try consolidation to build value per
share. Concurrently, we wanted to cre-
ate a company capable of sustainable
organic growth when industry consoli-
dation slowed down, or the economics
of acquisitions eroded.

This is exactly where Devon is
today. Devon has assembled the assets,
the expertise and the financial capacity
to grow—without additional acquisi-
tions. Our North American core assets
consistently provide low-risk, short cycle-
time reserve and production additions.
These are complemented by a significant
inventory of risk-balanced, high-impact
exploration projects that provide longer
term growth opportunities.

Does this mean we will never

make another acquisition? Probably
not. Evaluating, structuring and inte-
grating acquisitions are among Devon’s
core competencies. Should an opportu-
nity become available that is earnings
accretive and strategically attractive, we
will not hesitate to move.

Devon was historically a North
American onshore operator. Much of
your exploration is now focused on
offshore projects in the Gulf of
Mexico and abroad. What gives you
the confidence that Devon has the
capabilities required to succeed?

DARRYL SMETTE:
Nothing inspires
confidence like
success. Devon
made a strategic
decision in 2001 to
embark on a high-
impact exploration program in the Gulf
of Mexico. Since that time we have dra-
matically increased our holdings in the
deepwater Gulf, established a large
prospect inventory and made three signif-
icant discoveries. We believe that this
expertise translates well to West Africa
and Brazil. As in the Gulf of Mexico, we
have also had early success in Brazil. In
late 2004, we announced an oil discovery
on our BM-C-8 block offshore Brazil.

Devon did not establish this expert-
ise overnight. Beginning with our acqui-
sition of PennzEnergy in 1999, Devon
has acquired three companies with a sig-
nificant presence in the Gulf of Mexico
and international arenas. From each of
these companies, we have attempted to
keep the best assets and the best people.
As a result, Devon has assembled a good
deal of institutional expertise in offshore
and international operations.

We have demonstrated our operating

capabilities with the success of the
Devon-designed and operated Panyu
project in the South China Sea and
through our active role in the construc-
tion and deployment of the Red Hawk
cell spar in the deepwater Gulf.

D I S C O V E R I N G D E V O N

DISCOVER

A LOOK AT DEVON’S
PORTFOLIO OF OIL
AND GAS PROPERTIES —
DISCOVERING OUR
FULL POTENTIAL

VERINGDevon

PORTFOLIO OF OIL AND GAS PROPERTIES —
DISCOVERING OUR
FULL POTENTIAL
T

In 2004, we added 281 million equivalent barrels of
proved reserves from discoveries, extensions and perform-
ance revisions on our North American onshore proper-
ties. This far exceeded the 177 million equivalent barrels
these properties produced in 2004 and more than
replaced the 251 million equivalent barrels Devon pro-
duced company wide.

he acquisitions of Anderson Exploration
in 2001, Mitchell Energy in 2002 and
Ocean Energy
in 2003, dramatically
increased Devon’s operational footprint.
Devon quickly became one of the largest
independent oil and gas producers in North America and
one of the largest independent acreage holders in the deep
waters of the Gulf of Mexico and West Africa. However,
these transactions were not completed just to make
Devon bigger. The acquisitions and subsequent related
divestitures of non-core and low growth properties have
made Devon better. With an improved opportunity set,
Devon is now positioned with the properties, the expert-
ise and the financial resources to deliver sustainable
organic growth.

Devon’s growth strategy comprises near-term and
long-term elements. The near-term strategy relies upon
our onshore property base in the United States and
Canada to deliver repeatable, low-risk reserves and pro-
duction growth. To sustain growth over the longer term,
we are also investing in large-scale development projects
and high-impact exploration in frontier areas in North
America and abroad.

NORTH AMERICAN ONSHORE ASSETS
DELIVER REPEATABLE RESULTS

t the close of 2004, almost 80% of Devon’s oil
and gas reserves were concentrated in the
company’s core producing areas located onshore in the
United States and Canada. (Please refer to Operating
Statistics by Area on page 16 for this and other comparisons.)
These core onshore properties generate over 70% of
Devon’s current oil and gas production and are the target
of roughly three quarters of our 2005 exploration and pro-
duction capital budget.

10 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Not only do Devon’s core North American onshore
producing properties consistently deliver low-risk reserves
and production additions, they do so economically. The
281 million equivalent barrels added in 2004 resulted from
just over $2 billion of capital expenditures. These impres-
sive results reflect the performance of Devon’s core assets
across our North American asset base and Devon’s com-
mitment to deliver efficient growth. A discussion of some
of our most significant North American assets follows.

Wells Drilled

9
2
2
,
2

8
7
1
,
2

5
8
6
,
1

5
4
5
,
1

8
2
3
,
1

Reserve Additions
from Extensions,
Discoveries and
Performance
Revisions
(MMBoe*)

3
1
3

Net Undeveloped
Acreage
(Millions of Acres)

6
2

3
2

2
1 2
2

9
6
1

6
1

0
3
1

1
3
1

6
6

00 01 02 03 04

Devon drilled
more than 2,100
oil and gas wells
during 2004…

…and added over
300 million barrels
from discoveries,
extensions and per-
formance revisions.

* Gas converted to oil
equivalent at the ratio of
6Mcf:1Bbl.

We ended 2004
with more than 20
million net unde-
veloped acres on
which to drill in the
future.

This jackup rig is drilling adjacent to an offshore
production platform. Devon’s offshore operations include
the Gulf of Mexico, Brazil and West Africa.

PORTFOLIO OF OIL AND GAS PROPERTIES —
DISCOVERING OUR
FULL POTENTIAL

Barnett Shale

Since Devon entered the play with our acquisition of
Mitchell in January 2002, the Barnett Shale has rapidly
grown to become the largest gas field in the state of Texas
and has secured Devon’s position as the state’s largest gas
producer. In 2004, we produced more than 34 million
equivalent barrels from 1,900 Barnett Shale wells. During
the year, we drilled about 200 new wells and added 60
million equivalent barrels of new reserves.

When Devon acquired its Barnett Shale properties in
early 2002, we booked 310 million equivalent barrels of
proved reserves. Since then, we have produced about 92
million equivalent barrels from the Barnett Shale.
Remarkably, we have more reserves on the books today
than when we started, demonstrating the sustainability of
this exceptional asset.

More than 90% of our Barnett Shale wells are con-
centrated within a 120,000-acre area in Wise, Denton and
Tarrant counties known as the “core area.” Historically,
almost all of the production from the Barnett was derived
from this producing fairway. However, in 2002, Devon
pioneered horizontal drilling in the Barnett, proving that,
with this technique, the play could be economically
expanded outside the core area.

Our success in the Barnett has recently attracted a
host of industry competitors, but as the first mover, we
established the premier position in the play. We currently
produce more gas from the Barnett than all of our com-
petitors combined. We dominate the core area and have
more than 400,000 net acres outside the core. We are cur-
rently utilizing 3-D seismic and horizontal drilling to opti-
mize the development of this dominant position. In 2005,
we plan to drill more than 200 Barnett wells including
about 100 horizontals outside the core area. (Please refer
to the Key Property Highlights pull-out following page 16
for more information about the Barnett Shale and other
significant assets.)

12 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Carthage

The Carthage area in east Texas is another
core holding that continues to provide significant reserves
and production growth. In 2004, we drilled 92 wells in the
Carthage area and added 28 million equivalent barrels of
new reserves. Devon’s production from this area climbed
33%, to 11 million equivalent barrels in 2004. In 2005,
we plan to drill more than 100 wells in the Carthage area.
Our multi-year inventory of low-risk drilling locations
should yield years of additional growth.

Washakie

The Washakie field in the Rocky Mountains contin-
ues to be a source of repeatable growth for Devon. In
2004, we produced five million equivalent barrels, drilled
60 wells and added 14 million equivalent barrels of new
reserves. In 2005, we plan to drill 84 wells at Washakie
from a drilling inventory of some 300 locations.

Western Canadian Sedimentary Basin

With more than eight million net undevel-
oped acres in Canada, Devon has the largest Canadian
exploration portfolio of any U.S.-based independent. This
extensive property base consistently provides low-risk pro-
duction and reserves growth. In 2004, our Canadian pro-
duction increased by 4%, to 65 million equivalent barrels.
Our 2004 reserve additions from drilling and performance
revisions totaled 122 million equivalent barrels, or almost
twice the year’s production.

As in the United States, our 2004 Canadian reserves
growth was driven by assets spanning our base of large-
scale, low-risk oil and gas properties. The Deep Basin in
western Alberta and eastern British Columbia is one exam-
ple. Deep Basin drilling and performance improvements
added 30 million equivalent barrels of proved reserves in
2004. This compares with production of 12 million equiv-
alent barrels. From more than 480,000 net acres on which
to drill, Devon expects to add reserves and production in
the Deep Basin into the future.

In addition to our predominately conventional oil
and gas producing areas, Devon also owns more than
140,000 net acres in the promising Alberta oil sands. After
receiving final governmental approval in late 2004,
Devon’s 100%-owned Jackfish thermal oil sands project is
now under way. We expect Jackfish to ultimately add 300
million barrels to Devon’s reserves and to produce 35,000
barrels of oil per day in 2008 when fully operational.
(Please refer to the story on page 17 for more information
on the exciting Jackfish project.)

HIGH-IMPACT INVESTMENTS PROVIDE
LONG-TERM OPPORTUNITY

evon balances its low-risk, short cycle-time
investments in core producing areas with large-scale
development projects and high-impact exploration in
frontier areas. These activities, focused on building future
growth, are concentrated in the Gulf of Mexico and inter-
national arenas.

Gulf of Mexico—Deepwater

Recent successes in the deepwater Gulf of
Mexico provide glimpses of the rewards that may lie
ahead. These successes include new production from the
development of previous discoveries, the potential of
recent discoveries and the possible reward of exploratory
wells yet to be drilled.

In 2004, Devon brought two deepwater Gulf of
Mexico projects on production. Our 50%-owned Red
Hawk gas development project came on stream in July.
Red Hawk, on Garden Banks block 876, is currently pro-
ducing in excess of 120 million cubic feet of gas per day.
In December, our 25%-owned Magnolia project on
Garden Banks block 783 began producing. Magnolia is
still in the ramp-up stage, but in March it was producing
about 35,000 equivalent barrels per day from two of an
expected eight total producing wells.

Also in 2004, Devon entered into an agreement to
develop its 50%-owned Merganser gas discovery on
Atwater Valley block 37. This project is part of a coopera-
tive effort by a group of independent Gulf of Mexico oper-
ators. Under an innovative arrangement, production facil-
ities will be designed and built to receive gas from several
surrounding fields with varying ownership. This project
may serve as a model for other cooperative deepwater proj-
ects in the future. Devon has committed approximately 60
million cubic feet per day of Merganser production to the
project with first production expected in 2007.

In the deepwater Gulf of Mexico, most oil and gas
exploration and production has historically been from
Miocene age reservoirs. However, in recent years, deepwa-
ter operators have begun to test several older and deeper
formations. These formations are collectively known as
the “lower Tertiary.” These are highlighted in the illustra-
tion (right). Devon has made three potentially significant
lower Tertiary discoveries in the past three years.

We drilled our first lower Tertiary discovery in
2002, on the Cascade prospect. Cascade, in which Devon
has a 25% working interest, is located on Walker Ridge
block 206. In 2003, we made our second lower Tertiary

discovery at the St. Malo prospect on Walker Ridge block
678. Devon has a 22.5% working interest in St. Malo.
This past year we drilled a successful appraisal well at St.
Malo that encountered more than 400 net feet of oil pay.
Also in 2004, we drilled our third lower Tertiary discov-
ery. The 25% Devon-owned Jack well, on Walker Ridge
block 759, encountered more than 350 net feet of oil pay.
In 2005, we plan to drill delineation wells on
Cascade, St. Malo and Jack. In addition, we plan to carry
out a production test on one of these lower Tertiary dis-
coveries in 2005 or 2006. Should the information we
gather continue to be positive, we expect to sanction devel-
opment of one or more of these discoveries. At that point,
we would begin recognizing reserves in anticipation of first
production in 2008 or 2009.

Geologic Formations

PLEISTOCENE

PLIOCENE

MIOCENE

OLIGOCENE

EOCENE

PALEOCENE

CRETACEOUS

JURASSIC

Y
R
A

I
T
R
E
T

This chart illustrates the order in which these geologic
formations were deposited. The oldest and deepest for-
mations appear at the bottom of the column. Devon has
made three potentially significant discoveries in lower
Tertiary sands (highlighted in orange) that lie below the
Miocene.

PORTFOLIO OF OIL AND GAS PROPERTIES —
DISCOVERING OUR
FULL POTENTIAL

In addition to our deepwater discoveries to date, we
currently have an inventory of 23 untested lower Tertiary
opportunities and 18 untested Miocene opportunities. This
prospect inventory will support a robust deepwater Gulf of
Mexico exploration program for years to come. However, it
represents only a small portion of the 500 plus acreage
blocks in which Devon has an interest in the deepwater
Gulf. From this extensive acreage inventory and our ongo-
ing participation in lease sales, we are continuously regen-
erating our deepwater prospect inventory.

Gulf of Mexico—Deep Shelf

Devon’s high-impact exploration program in the
Gulf of Mexico is not limited to the deep water.
Significant resource potential also remains far beneath the
shallower Gulf waters in the “deep shelf.” Deep shelf wells
are drilled in water less than 600 feet deep but target reser-
voirs below 15,000 feet. Some of these deep shelf
prospects target lower Tertiary formations. Devon plans to
test several deep shelf prospects in 2005 from an inven-
tory of 28 prospects.

INTERNATIONAL OPPORTUNITIES
DIVERSIFY PORTFOLIO

n addition to our high impact exploration and devel-
opment projects in the Gulf of Mexico, Devon has
many large-scale exploration and development projects
under way in the international arena. Although properties
outside North America currently account for less than
15% of Devon’s company-wide production, these assets
hold the potential to deliver meaningful reserves and pro-
duction growth in the future. Devon’s international assets
include both established producing properties and high-
impact exploration projects.

Zafiro Field

The Zafiro field offshore Equatorial Guinea is
Devon’s largest international producing property. Devon’s
share of production from Zafiro averaged 47,000 barrels
per day in 2004, or about 50% of our total international
production. Additional drilling opportunities at Zafiro
should help maintain overall field production in 2005.
While Devon’s share of Zafiro production is expected to
decline in mid-2005 under the terms of the production
sharing contract, we expect Zafiro to be a profitable source
of reserve additions for years to come.

11-Year Property Data (1)

Reserves (Net of royalties)

Oil (MMBbls)
Gas (Bcf )
NGLs (MMBbls)
Oil, Gas and NGLs (MMBoe) (2)
10% Present Value Before Income Tax (Millions) (3)

Production (Net of royalties)

Oil (MMBbls)
Gas (Bcf )
NGLs (MMBbls)
Oil, Gas and NGLs (MMBoe) (2)

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

Unit Production and Operating Expense (Per Boe) (2)

1994

1995

1996

1997

1998

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

166
1,440
21
427
1,375

20
189
3
55

12.28
1.78
8.08
11.09

4.29

(1) All the years shown 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 continuing operations since 2003. Data has been restated to reflect the 1998 merger of
Devon and Northstar and the 2000 merger of Devon and Santa Fe Snyder in accordance with the pooling-of-interests method of accounting.

(2) Gas converted to oil at the ratio of 6Mcf:1Bbl. Natural gas liquids converted to oil at the ratio of 1Bbl:1Bbl.
(3) See note 2 on page 16.

14 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

ACG Field

The ACG field, a five billion barrel oil resource
located offshore Azerbaijan in the Caspian Sea, is expected
to produce more than one million barrels per day by 2009.
Under the terms of Devon’s 5.6% “carried interest” in
ACG, our accumulated development costs must be repaid
to the carrying partners prior to Devon’s full participation
in the production stream. Full-scale development of ACG
has awaited an oil export pipeline that is on track for com-
pletion in 2005. Although Devon’s share of current pro-
duction is minor, we expect it to climb to as much as
50,000 barrels per day following payout of the carry in
2007 or 2008.

South Atlantic Margin Exploration

Devon has assembled a significant inventory of high-
impact exploration prospects offshore Brazil and offshore
West Africa. Our exploration holdings in West Africa
include offshore concessions in Angola, Gabon, Ghana,
Equatorial Guinea and Nigeria. In aggregate, Devon’s 11
licensed blocks represent more than five million net unde-
veloped acres. In Brazil, we hold five licensed blocks com-
prising over 700,000 net acres. The prospective targets in
these areas are large enough to be meaningful to Devon as
a whole—generally several hundred million barrels or more
per prospect. As with most exploration wells, the chance of
success on any individual prospect is relatively low.

However, the likelihood of a significant discovery from
Devon’s extensive portfolio of prospects is much higher.
During 2005, we plan to test seven of our exploratory
prospects in West Africa.

Offshore Nigeria, we are currently drilling the first
of two exploratory wells on Devon-operated block 256.
The Tari well is testing a prospect with gross reserve
potential of more than 500 million barrels. With a work-
ing interest of 37.5% in block 256, Devon’s share of a dis-
covery could be substantial. Devon also operates and
intends to retain a 37.5% working interest in Nigerian
block 242, which we plan to test in 2006.

We will also drill exploratory wells on blocks B and
P in Equatorial Guinea and on blocks 10 and 24 offshore
Angola in 2005. The deepwater of West Africa is an explo-
ration frontier with very large resource potential. These
opportunities plus Devon’s extensive Gulf of Mexico
prospect inventory combine to hold billions of barrels of
reserve potential.

During 2004, we made an oil discovery on block
BM-C-8 in Brazil. We plan additional drilling and a pro-
duction test on the block in 2005, with the intent of estab-
lishing a commercial development project. Also in 2004,
we acquired two additional deepwater blocks in the pro-
lific inner trend of the Campos Basin offshore Brazil. We
plan to drill wells on each of these blocks in 2006. n

1999

2000

2001

2002

2003

2004

5–YEAR
COMPOUND
GROWTH RATE

10–YEAR
COMPOUND
GROWTH RATE

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

596
7,494
232
2,077
23,428

78
891
24
251

28.18
5.32
23.04
29.88

6.13

6%
22%
33%
17%
35%

26%
25%
37%
26%

10%
21%
12%
16%

7%
26%
35%
17%
32%

11%
24%
35%
19%

8%
12%
9%
10%

D I S C O V E R I N G D E V O N

P O R T F O L I O O F O I L A N D G A S P R O P E R T I E S

Operating Statistics by Area

Producing Wells at Year-end

9,122

5,511

5,433

3,855

1,205

25,126

7,878

545

33,549

PERMIAN

CONTINENT MOUNTAINS

MID-

ROCKY

GULF
COAST

U.S.
OFFSHORE

TOTAL
U.S.

CANADA

INTERNATIONAL COMPANY

TOTAL

2004 Production (Net of royalties)

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

Average Prices

Oil price ($/Bbl)
Gas price ($/Mcf )
NGLs price ($/Bbl)
Oil, Gas and NGLs ($/Boe) (1)

Year-end Reserves (Net of royalties)

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

Year-end Present Value of Reserves (Millions) (2)

Before income tax
After income tax

Year-end Leasehold (Net acres in thousands)

Producing
Undeveloped

Wells Drilled During 2004

Capital Costs Incurred (Millions) (3)

2004 Actual (4)
2005 Forecast

9
55
3
22

—
191
11
43

2
102
1
20

28.46
5.37
19.20
28.71

95
368
25
181

—
4.92
20.69
27.42

4
1,847
108
420

37.91
4.94
12.49
29.85

21
998
9
196

2
133
3
27

33.81
5.73
26.86
33.54

15
1,145
35
241

18
121
1
39

30.69
6.31
26.78
34.27

68
578
5
170

31
602
19
151

30.84
5.43
21.47
30.80

203
4,936
182
1,208

14
279
5
65

21.60
5.15
29.23
28.80

147
2,420
50
600

33
10
—
35

28.40
3.33
21.12
27.92

246
138
—
269

78
891
24
251

28.18
5.32
23.04
29.88

596
7,494
232
2,077

2,167

3,733

2,056

2,772

2,966

13,694
9,374

5,636
3,881

4,098
2,830

23,428
16,085

$
$
$
$

$
$

327
463

350

679
433

351

526
862

328

583
502

211

519
1,630

2,634
3,890

2,383
8,294

325
10,433

5,342
22,617

1,257

849

2,178

198
$
$ 145-165

446
410-470

171
220-255

330
305-350

455

960
425-480 1,505-1,720 1,045-1,180

1,600

292

2,852

305-380 2,855-3,280

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

Estimated future revenue to be generated from the production of proved reserves, net of estimated future expenditures, discounted at 10% in accordance with SFAS No. 69, Disclosures about
Oil and Gas Producing Activities. Devon believes that the pre-tax 10% present value is a useful measure in addition to the after-tax value as it assists in both the determination of future cash
flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax present value is dependent on the unique tax situation of each individual
company while the pre-tax present value is based on prices and discount factors which are consistent from company to company. We also understand that securities analysts use this after-tax
measure in similar ways.
2004 actual costs incurred and 2005 forecasted capital costs include exploration and production expenditures, capitalized general and administrative costs, capitalized interest costs and asset
retirement costs.
2004 actual costs incurred also include proved property acquisitions of $15 million, $9 million, $3 million and $11 million in the Permian, Rocky Mountains, U.S. Offshore and Canada, respectively.

(3)

(4)

Year-end 2004
Proved Oil and Gas
Reserves by Area

13%

29%

2005 Exploration and
Production Expenditures
Budget

12%

20%

9% 14%

11%

15%

5%8%

38%

n Permian
n Mid-Continent
n Rocky Mountains
n Gulf Coast
n U.S. Offshore
n Canada
n International

16 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

WESTERN CANADIAN
SEDIMENTARY BASIN

• Calgary

(Division Office)

BIG
HORN
BASIN

WIND
RIVER
BASIN

POWDER
RIVER
BASIN

GREEN
RIVER
BASIN

WASHAKIE
BASIN

UINTA
BASIN

SAN
JUAN
BASIN

H Oklahoma City
(Headquarters
& Division Offices)

FT. WORTH
BASIN

PERMIAN

BASIN

• Houston

(Division Offices)

Areasof
Operation

PERMIAN

CANADA

Devon’s operations in the
Permian Basin of west Texas and
southeast New Mexico provide
the company with both oil and gas
production. The Permian Basin was
the source of some of the earliest
oil and gas discoveries in the United
States. It covers about 66,000 square
miles and contains hundreds of
oil and gas fields. It continues to
offer exploration and low-risk
development opportunities from
many geologic reservoirs and depths.

MID-CONTINENT

Devon’s Mid-Continent

operations encompass Oklahoma,
the Texas panhandle and north
Texas. Devon’s most important Mid-
Continent asset is the prolific
Barnett Shale field in the Fort
Worth Basin. Acquired in the 2002
acquisition of Mitchell Energy, it is
the largest natural gas field in Texas
and among the fastest growing
onshore natural gas fields in North
America. Devon’s position in the
Barnett includes 535,000 net acres
and about 1,900 producing wells.

ROCKY MOUNTAINS

Devon’s Rocky Mountain
operations extend from New
Mexico to Montana. Some of
Devon’s most significant properties
lie in the gas-prone Washakie, Wind
River, Big Horn and Green River
basins in Wyoming, the Bear Paw
field in north-central Montana and
the oil-prone Uinta basin in Utah.
Devon was a pioneer in coalbed
natural gas, advancing one of the
first and most successful projects in
the world—the Northeast Blanco
Unit in the San Juan Basin. Devon
also holds a significant coalbed
natural gas position in Wyoming’s
Powder River Basin.

GULF COAST

Devon’s Gulf Coast operations

include south and east Texas,
Louisiana and Mississippi. Most
reserves in the region come from
long-lived oil and natural gas
reservoirs found in conventional
sandstone formations. Many of
these have been rejuvenated in
recent years through the use of 3-D
seismic technology. Low-risk, infill
development drilling and
recompletion activities are ongoing
in the Carthage and Groesbeck
areas of east Texas.

GULF OF MEXICO

Devon is one of the 10 largest
oil and gas producers in the Gulf
of Mexico with interests in more
than 700 offshore blocks. On the
shelf, with water depths to 600
feet, Devon is participating in a
new wave of exploratory drilling
targeting formations below 15,000
feet. The deepwater Gulf (deeper
than 600') is a promising frontier
area believed to hold some of the
largest remaining undiscovered
reserves in North America. Devon
is one of the largest independent
deepwater Gulf leaseholders. From
this inventory, the company has
drilled three discoveries in the
emerging lower Tertiary trend.
These discoveries and more than 20
additional prospects have the
potential to add significant reserves
to Devon in the future.

Devon is among the largest

independent oil and gas producers in
Canada. Most of the country’s
producing fields are located in the
Western Canadian Sedimentary
Basin. Devon’s Canadian oil and gas
production includes conventional
resources, cold-flow heavy oil and
thermal heavy oil. Many areas are
restricted to winter-only access,
which requires drilling activity to be
concentrated in the coldest months.
Devon also holds extensive
exploratory acreage far to the north
in the Mackenzie Delta and Beaufort
Sea. These areas are believed to hold
significant undiscovered oil and gas
resources but currently lack pipeline
infrastructure.

AZERBAIJAN

One of Devon’s largest

concentrations of proved reserves
outside North America is located
offshore Azerbaijan in the Caspian
Sea. Devon has a 5.6% carried
interest in the five billion barrel
Azeri-Chirag-Gunashli (ACG)
oil development project. Upon
completion of the Baku-T’Bilisi-
Ceyhan pipeline in 2005, Azerbaijan
will become a significant supplier of
crude oil to world markets. Devon’s
net share of production is expected
to reach as much as 50,000 barrels
per day in 2007 or 2008.

CHINA

In China, Devon discovered
and developed the Panyu Field in
the South China Sea. Two fixed
platforms were installed 11 miles
apart. Oil is piped from these
platforms to a nearby FPSO. The
Devon operated field achieved first
production in 2003. Exploration
potential targeting nearby satellite
fields is being evaluated using the
company’s large 3-D seismic
database.

EGYPT

In Egypt, Devon has interests
in eight licensed blocks, three in the
Western Desert and five operated by
Devon in the Gulf of Suez. In total,
these blocks cover approximately
3.9 million gross acres. Four of
these concessions are currently
producing.

WEST AFRICA

Some of Devon’s most

significant international exploration
and production projects lie under
the waters of coastal West Africa.
The company’s largest international
producing property is the Zafiro
field located offshore Equatorial
Guinea. Southern expansion of
the field in 2003 pushed gross
production from Zafiro to 300,000
barrels of oil per day. In 2005,
Devon will drill exploratory wells
in Equatorial Guinea, Angola
and Nigeria.

BRAZIL

Devon holds interests in five
exploration blocks offshore Brazil
covering more than one million
gross acres. In 2005, the company
will drill follow-up wells to its 2004
discovery on block BM-C-8.

KEY PROPERTY HIGHLIGHTS

B Magnolia

B Northeast British Columbia

COLORADO

KANSAS

NEW
MEXICO

OKLAHOMA

TEXAS

PERMIAN

A Southeast New Mexico

Profile
•

75% average working interest in 544,000 acres in
southeast New Mexico.

• Key fields include Ingle Wells, Gaucho, West Red Lake,

Catclaw Draw and Outland.

• Produces oil and gas from multiple formations at 1,500’

•

to 16,500’.
65.8 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 33 gas wells.
• Drilled and completed 61 oil wells.
• Recompleted 33 wells.
2005 Plans
• Drill 25 gas wells.
• Drill 42 oil wells.
• Recomplete 34 wells.
• Divest non-core properties.

B West Texas

Profile
•

40% average working interest in 1.1 million acres in
west Texas.

• Key fields include Wasson and Anton-Irish to the north
and Ozona, Keystone/Kermit and Waddell to the south.
• Produces oil and gas from multiple formations at 2,500’

•

to 18,000’.
115.5 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 37 gas wells.
• Drilled and completed 19 oil wells.
• Recompleted 26 wells.
2005 Plans
• Drill 17 gas wells.
• Drill 36 oil wells.
• Recomplete 53 wells.
• Divest non-core properties.

KANSAS

MISSOURI

OKLAHOMA

ARKANSAS

TEXAS

B Powder River Coalbed Natural Gas

Profile
•

75% average working interest in 346,000 acres
in northeastern Wyoming.

• Produces coalbed natural gas from the Fort Union Coal

•

Installed vacuum compression for 260 wells.

formations at 300’ to 2,000’.
14.7 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled 155 coalbed natural gas wells.
• Connected 111 wells to gas sales.
• Recompleted 34 wells.
•
• Acquired additional interest in North Rough Draw field
and expanded Juniper Draw field through acreage
trades.
2005 Plans
• Drill 120 coalbed natural gas wells.
• Deepen 44 wells.
• Recomplete 10 wells.
•

Install vacuum compression on 53 wells.

C Washakie

Profile
•

76% average working interest in 210,000 acres
in southern Wyoming.

• Produces gas from multiple formations at 6,800’

•

to 10,300’.
85.7 million barrels of oil equivalent reserves
at 12/31/04.
2004 Activity
• Drilled and completed 60 wells.
• Recompleted 7 wells.
•

Initiated plunger installation program to stimulate
production.
2005 Plans
• Drill 84 wells.
• Recomplete 8 wells.
•

Install up to 200 plungers.

D 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 237 coalbed natural gas wells and 207
conventional wells.

• Produces primarily coalbed natural gas from the

•

Fruitland Coal formation at 3,000’.
21.7 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 51 infill coalbed natural gas wells.
• Completed 11-well workover program.
•
Installed 16 pumping units for water removal.
• Drilled and completed 21 conventional gas wells.
• Recompleted 2 conventional wells.
2005 Plans
• Drill 27 infill coalbed natural gas wells.
Initiate 15-well workover program.
•
•
Install 17 pumping units for water removal.
• Drill 33 conventional gas wells.
• Recomplete 14 conventional wells.

LOUISIANA

TEXAS

LOUISIANA

GULF
OF MEXICO

GULF COAST

A Carthage Area

Profile
•

85% average working interest in 176,000 acres in
east Texas.

• Key fields include Carthage, Bethany, Waskom,

Stockman and Appleby.

• Produces from the Pettit, Travis Peak and Cotton Valley

•
•

formations at 5,700’ to 9,600’.
Includes 1,370 producing wells.
127.2 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 92 wells.
• Recompleted 80 wells.
2005 Plans
• Drill 106 wells.
• Recomplete 65 wells.
• Expand gathering system capacity at Carthage.

B Groesbeck Area

Profile
•

72% average working interest in 191,000 acres in east
central Texas.

• Key fields include Personville, Nan-Su-Gail, Dew and

Bald Prairie.

• Produces from the Travis Peak, Cotton Valley and

•
•

Bossier formations at 6,000’ to 13,000’.
Includes 520 producing wells.
39.8 million barrels of oil equivalent reserves
at 12/31/04.
2004 Activity
• Drilled and completed 49 wells.
• Recompleted 47 wells.
2005 Plans
• Drill 37 wells.
• Recomplete 10 wells.

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

Houston area and Pettus/Ray Ranch.

•

• Produces oil and gas from the Frio/Vicksburg, Yegua,
Wilcox and Woodbine trends at 1,500’ to 15,000’.
45.7 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 70 wells.
• Recompleted 97 wells.
2005 Plans
• Drill 57 wells.
• Recomplete 41 wells.
• Divest non-core properties.

NEBRASKA

C South Texas

MID-CONTINENT

A Barnett Shale

Profile
•

535,000 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.
• Produces gas from the Barnett Shale formation

•

at 6,500’ to 8,500’.
323.8 million barrels of oil equivalent reserves
at 12/31/04.
2004 Activity
• Drilled 149 wells within core area, including:

100 vertical infill wells.
49 horizontal wells.

• Drilled 51 wells outside core area, including:

12 vertical wells.
39 horizontal wells.

• Refractured 27 wells in core area.
• Acquired 3-D seismic and acreage.
2005 Plans
• Drill 125 wells within core area, including:

70 vertical infill wells.
55 horizontal wells.

• Drill 101 horizontal wells outside core area.
• Refracture 30 wells.
• Acquire additional 3-D seismic and acreage.

MONTANA

NORTH
DAKOTA

SOUTH
DAKOTA

WYOMING
C

COLORADO

IDAHO

UTAH

KANSAS

ROCKY MOUNTAINS

A Bear Paw

Profile
470,000 net acres in north central Montana.
•
90% average working interest in federal units.
•
•
75% average working interest outside federal units.
• Produces gas from the Eagle formation at 800’ to 2,000’.
•

19.3 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 39 wells.
• Performed 48-well workover program.
2005 Plans
• Drill up to 83 wells, including 1 deeper exploratory well.
• Evaluate coalbed natural gas potential.
• Continue workover program.

MISSISSIPPI

TEXAS

LOUISIANA

GULF
OF MEXICO

GULF OFFSHORE – SHELF

A Eugene Island 126 Area

Profile
•

Includes 12 blocks located in and around Eugene Island
126.

• Working interests range from 25% to 100%.
•
Located offshore Louisiana in 40’ of water.
• Produces oil and gas from sands at 4,500’ to 10,500’.
•
2004 Activity
• Drilled and completed Tikal discovery at Eugene Island

5.3 million barrels of oil equivalent reserves at 12/31/04.

142.
•
Installed production facilities for Tikal discovery.
• Drilled and completed 1 development well at Eugene

Island 125.

25% working interest in Garden Banks 783 and 784.
Located offshore Louisiana in 4,700’ of water.

Profile
•
•
• Developing 1999 discovery.
• Produces oil and gas from sands at 12,000’ to 17,000’.
• Utilizes the world’s deepest tension-leg platform.
21.3 million barrels of oil equivalent reserves at
•
12/31/04.
2004 Activity
•

Finished construction and installation of the tension-leg
platform.

• Completed 1 well.
• Commenced production.
2005 Plans
• Complete remaining 7 wells.
• Evaluate potential for additional drilling.
• Evaluate third party tie-ins.

C Red Hawk

Profile
•

50% working interest in Garden Banks 876, 877, 920
and 921.
Located offshore Louisiana in 5,300’ of water.
2001 discovery.

•
•
• Produces gas from sands at 16,000’ to 18,500’.
• Utilizes the world’s first cell spar.
•
2004 Activity
•
• Commenced production from 2 wells at facility capacity

8.1 million barrels of oil equivalent reserves at 12/31/04.

Finished construction and installation of cell spar.

of 120 million cubic feet per day gross.

2005 Plans
• Evaluate potential for additional drilling.

D Merganser (Independence Hub)

• Performed 6-well recompletion program at Eugene

Island 126 area.

2005 Plans
• Commence production from Tikal discovery.
• Evaluate development potential at Eugene Island 125.
• Evaluate exploration potential at Eugene Island 108.

50% working interest in Atwater Valley 37.
Located offshore Louisiana in 8,100’ of water.

Profile
•
•
• Developing 2001 discovery.
• To produce gas from sands at 19,000’ to 20,000’.
• Cooperative development of 6 nearby industry

Profile
•

73% average working interest in 2.2 million acres in
northwestern Alberta and northeastern British
Columbia.

• Key areas include Ring Border, Hamburg, Tooga/Peggo,

Tommy Lakes and Wargen.
• Primarily winter-only drilling.
• Produces oil and gas from multiple formations at 8,000’

•

to 10,000’.
77.0 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Completed 110 of 115 wells drilled, including:

30 wells at Ring Border.
16 wells at Wargen.
15 wells at Tooga/Peggo.

• Added booster compressors at Tooga and Septimus.
2005 Plans
• Drill 104 total wells, including:

29 wells at Ring Border.
16 wells at Tooga/Peggo.
16 wells at Wargen.
14 wells at Hamburg/Chinchaga.

C Peace River Arch

Profile
•

68% average working interest in 1.2 million acres in
western Alberta.

• Key areas include Dunvegan, Cecil, Eaglesham, Belloy,

Pouce Coupe and Valhalla.

• Produces liquids-rich gas and light gravity oil from

•

multiple formations at 4,500’ to 8,000’.
93.6 million barrels of oil equivalent reserves
at 12/31/04.
2004 Activity
• Completed 133 of 149 wells drilled, including:

35 wells at Dunvegan.
19 wells at Cecil.
13 wells at Belloy.
11 wells at Eaglesham.

2005 Plans
• Drill 111 total wells, including:
42 wells at Dunvegan.
14 wells at Cecil.
11 wells at Belloy.
10 wells at Eaglesham.

D Deep Basin

Profile
•

47% average working interest in 1.5 million acres
in western Alberta and eastern British Columbia.

• Operate 76% of company production.
• Key areas include Wapiti, Elmworth, Bilbo, Leland and

• Produces liquids-rich gas primarily from Cretaceous

•

formations at 3,000’ to 14,000’.
97.7 million barrels of oil equivalent reserves
at 12/31/04.
2004 Activity
• Completed 182 of 187 wells drilled, including:

47 wells at Wapiti.
38 wells at Bilbo.
33 wells at Elmworth.
25 wells at Pinto.

• Expanded production facilities at Leland.
• Added compression at Bilbo.
2005 Plans
• Drill 157 total wells, including:
50 wells at Wapiti.
41 wells at Elmworth.
22 wells at Bilbo.
20 wells at Pinto.

E Foothills

Profile
•

52% working interest in 1.2 million acres in western
Alberta and eastern British Columbia.

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

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

•

15,000’.
84.7 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Completed 26 of 28 wells drilled, including:

12 wells at Narraway.
5 wells at Findley.

Installed additional compression at Findley.

•
2005 Plans
• Drill 32 total wells, including:

10 wells at Narraway.
7 wells at Grizzly Valley.
4 wells at Bighorn.
3 wells at Coleman.
3 wells at Findley.

F Thermal Heavy Oil

Profile
•

52% average working interest in 281,000 acres in
eastern Alberta oil sands.

recovery method.
300 million barrel potential at Jackfish.

•
2004 Activity
• Drilled all stratigraphic appraisal wells at Jackfish.
• Received final regulatory approvals for Jackfish project.
2005 Plans
•
•
• Drill 40 stratigraphic wells to evaluate potential near

Initiate drilling 23 horizontal well pairs at Jackfish.
Initiate Jackfish facility construction.

Lower Tertiary Discoveries

Pinto.

discoveries utilizing subsea tie-backs to a central
production hub.
9.0 million barrels of oil equivalent reserves at 12/31/04.

•
2004 Activity
•
• Received project sanctioning.
• Committed 60 million cubic feet per day to

Finalized central hub development option.

Independence Hub.

2005 Plans
• Sidetrack and complete 2 wells.
•

Initiate facility and subsea construction.

Profile
E CASCADE
25% working interest in Walker Ridge 206.
•
•
Located offshore Louisiana in 8,200’ of water.
• Target formation: lower Tertiary sands at 25,000’

to 27,000’.

25% working interest in Walker Ridge 759.
Located offshore Louisiana in 7,000’ of water.

22.5% working interest in Walker Ridge 678.
Located offshore Louisiana in 6,900’ of water.

• Discovery well drilled in 2002.
F ST. MALO
•
•
• Target formation: lower Tertiary sands.
• Discovery well drilled in 2003.
• > 450’ of net oil pay.
G JACK
•
•
• Target formation: lower Tertiary sands.
• Discovery well drilled in 2004.
• > 350’ of net oil pay.
2004 Activity
• Drilled successful appraisal well at St. Malo.
• Drilled discovery well at Jack.
•
2005 Plans
• Drill appraisal well at Cascade.
• Drill second appraisal well at St. Malo.
• Drill appraisal well at Jack.

Finalized Cascade appraisal well location with partners.

Deepwater Exploration Prospects

12.5% working interest in Mississippi Canyon 937.
Located offshore Louisiana in 4,000’ of water.

20% working interest in Green Canyon 320.
Located offshore Louisiana in 2,700’ of water.

Profile
H CHILKOOT
•
•
• Target formation: Miocene sands.
• Expected total depth: 32,000’.
I MAKALU
•
•
• Target formation: Miocene sands.
• Expected total depth: 30,400’.
J MISSION DEEP
•
•
• Target formation: Miocene sands.
K STURGIS NORTH
•
•
• Drilled 2003 oil discovery at Sturgis South.
• Expected total depth: 30,000’.
• Potential drill in 2005-2006.
2004 Activity
•
2005 Plans
•
• Drill exploratory test wells.

Finalize technical evaluation.

Initiated drilling at Makalu.

50% working interest in Green Canyon 955.
Located offshore Louisiana in 6,500’ of water.

25% working interest in Atwater Valley 182.
Located offshore Louisiana in 3,700’ of water.

B West Cameron 165/291

Profile
100% working interest.
•
•
Located offshore Louisiana in 50’ of water.
• Produces gas from sands at 9,000’ to 15,000’.
•
2004 Activity
• Drilled and completed Star discovery well at West

2.1 million barrels of oil equivalent reserves at 12/31/04.

Cameron 165.
Initiated drilling on follow-up well.

•
2005 Plans
• Complete follow-up well.
• Drill 1 additional follow-up well.
• Evaluate exploration potential on West Cameron 164

and 291.

Shelf Exploration Prospects

Located offshore Texas in 330’ of water.

Profile
C BIG BEND
• Mustang Island A110.
•
• Target formation: Miocene.
• Expected total depth: 19,500’.
•
• Net unrisked reserve potential: 30 million barrels

50% working interest.

of oil equivalent.

Located offshore Louisiana in 110’ of water.

D CADILLAC
• Viosca Knoll 251.
•
• Target formation: Cotton Valley at 19,900’ to 25,000’.
•
• Net unrisked reserve potential: 122 million barrels

10% working interest.

of oil equivalent.

E CHOPIN
• Eugene Island 334.
•
• Target formation: middle Pliocene sands at 11,000’

Located offshore Louisiana in 250’ of water.

to 12,500’.
100% working interest.

•
• Net unrisked reserve potential: 3 million barrels

of oil equivalent.

F JOSEPH
• High Island 10L.
•
•

Located offshore Louisiana in 30’ of water.
First lower Tertiary exploratory well in the western
Gulf of Mexico shelf.

20% working interest.

• Expected total depth: 24,000’.
•
G RACER
• West Cameron 575.
•
• Target formation: Lentic sands at 13,000’ to 14,000’.
•
• Net unrisked reserve potential: 4 million barrels of oil

Located offshore Louisiana in 200’ of water.

100% working interest.

Initiated drilling of Big Bend prospect.
Initiated drilling of Joseph prospect.

equivalent.
2004 Activity
•
•
2005 Plans
•
• Drill exploratory test wells.

Finalize geophysical analysis and drilling contracts.

MISSISSIPPI

TEXAS

LOUISIANA

GULF
OF MEXICO

B H
C

J
E

GULF OFFSHORE – DEEPWATER

A Nansen/Boomvang Complex

Includes 18 blocks in central East Breaks area.
50% working interest at the Nansen facility.
20% working interest at the Boomvang facility.
Located offshore Texas in 3,500’ of water.

Profile
•
•
•
•
• Produces oil and gas from sands at 9,000’ to 14,000’.
• Utilizes the world’s first open-hull truss spars.
•

58.9 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Evaluated potential for additional drilling at Nansen.
• Commenced production from 3 new subsea wells at

Boomvang.
2005 Plans
• Drill 1 to 4 wells at Nansen.
•
• Divest interest in Boomvang complex.

Initiate 4-well recompletion program at Nansen.

I
K

YUKON
TERRITORY

NORTHWEST
TERRITORIES

NUNAVUT

Jackfish.

• Divest Dover and Surmont projects.

B
BRITISH
C
COLUMBIA
E
D
ALBERTA

MANITOBA

SASKATCHEWAN

CANADA

A 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.

• Drilling limited to winter only.
•

2002 Tuk M-18 discovery estimated at 200-300 billion
cubic feet gross.

2004 Activity
• Received regulatory approval for 2005 Beaufort Sea well.
2005 Plans
• Drill 1 exploratory well in the Beaufort Sea.

ASIA

E
AFRICA
C
D

SOUTH
AMERICA

INTERNATIONAL

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.

• Major oil export pipeline to be completed in 2005.
• Expect up to 50,000 barrels per day net to Devon in 2007

•

– 2008.
94.6 million barrels of oil equivalent reserves at
12/31/04.

2004 Activity
• Drilled and completed 2 wells from the Chirag platform.
•

Installed Central Azeri platform and production
facilities.

• Pre-drilled 21 wells for future production from the

Central, East and West Azeri platforms.

2005 Plans
• Drill 3 wells from the Chirag platform.
• Complete 12 pre-drilled wells and commence
production from the Central Azeri platform.
Install West Azeri structure.

•
• Continue design and construction of East Azeri, West

•

Azeri and deepwater Gunashli facilities.
Install compression and water injection platform in
Central Azeri field.

• Export first oil through BTC Pipeline.

B China – Panyu

Profile
•

24.5% working interest in 719,000 acres in block
15/34 offshore China.
Located in the Pearl River Mouth Basin in 300’ of water.

•
• Produces oil from 1998 and 1999 discoveries.
•

16.1 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Drilled and completed 20 development wells.
• Drilled 2 exploratory test wells, resulting in 1 discovery.
• Ramped up production to a peak rate of 85,000 barrels

per day gross.
Initiated debottlenecking operations on the FPSO.

•
2005 Plans
• Drill 9 development wells.
• Drill 2 to 3 exploratory wells in satellite fields.
•
• Continue debottlenecking efforts on FPSO.

Install water handling facilities on each platform.

C Equatorial Guinea – Zafiro

Profile
•

23.75% working interest in 35,900 acres in the Zafiro
field in block B offshore Equatorial Guinea (E.G.).
Field facilities include 1 fixed production platform and 2
floating production vessels in 500’ to 2,500’ of water.
• Contains 59 producing wells, 20 water injection wells

•

and 1 gas injection well.

• Produces oil from a complex system of reservoir

•

channels at 5,000’ to 6,000’.
95.6 million barrels of oil equivalent reserves at
12/31/04.
2004 Activity
• Reached cost recovery payout.
• Drilled and completed 9 producing wells.
• Drilled and completed 8 injection wells.
2005 Plans
• Drill 8 to 10 development wells.
• Drill 1 injection well.
• Evaluate 3-D seismic data for future potential.
• Upgrade FPSO and platform facilities.

D South Atlantic Margin Exploration

Profile
•

11.6 million acres in 11 licensed blocks offshore
West Africa:

Angola block 10; 35% interest.
Angola block 16; 15% interest.
Angola block 24; 65% interest.
E.G. block B; 23.75% interest.
E.G. block C; 24.44% interest.
E.G. block N; 34% interest.
E.G. block P; 38.4% interest.
Gabon Agali block; 50% interest.
Ghana Keta block; 90% interest.
Nigeria block 256; 37.5%* interest.
Nigeria block 242; 75% interest.
* Subject to government approval.

•

1.0 million acres in 5 licensed blocks offshore Brazil:

Block BC-2; 15% interest.
Block BM-BAR-3; 100% interest.
Block BM-C-8; 60% interest.
Block BM-C-30; 25% interest.
Block BM-C-32; 40% interest.

2004 Activity
• Completed farmout agreement with industry partner

on block C in E.G.

• Drilled 1 exploratory dry hole on block P in E.G.
• Secured farmout agreements with industry partners

on block 256 in Nigeria.

• Acquired block 242 in Nigeria.
• Drilled discovery well on block BM-C-8 in Brazil.
• Acquired blocks BM-C-30 and BM-C-32 in Brazil.
2005 Plans
• Drill 2 exploratory wells on block 10 in Angola.
• Drill 1 exploratory well on block 24 in Angola.
• Drill 1 exploratory well on block B in E.G.
• Acquire 2-D seismic on block N in E.G.
• Drill 1 exploratory well on block P in E.G.
• Solicit farmout on the Keta block in Ghana and Angola

block 24.

• Drill 2 exploratory wells on block 256 in Nigeria.
• Complete farmout agreements with industry partners

on block 242 in Nigeria.

• Acquire 3-D seismic on block 242 in Nigeria.
• Drill 3 to 5 exploratory and appraisal wells on block

BM-C-8 in Brazil.

in Brazil.

E Egypt – Gulf of Suez Exploration

Profile
•

345,000 acres in 5 licensed blocks in the Gulf of Suez
offshore Egypt:

Ras Abu Darag; 50% interest.
Southeast July; 50% interest.
East Zeit; 100% interest.
North Zeit Bay; 50% interest.
Southwest Gebel El Zeit; 43.75% interest.

2004 Activity
• Secured farmout agreement with industry partner

on Ras Abu Darag, North Zeit Bay and Southeast July.

• Spud first of three-well exploration program on

Ras Abu Darag.

• Drilled and completed 1 exploratory well on East Zeit

and initiated drilling on second.

• Drilled 1 exploratory dry hole on Southeast July.
• Acquired 3-D seismic on Southwest Gebel El Zeit.
• Drilled 1 exploratory dry hole on Khaligue El Zeit and

relinquished block.

2005 Plans
• Drill 2 exploratory wells and acquire 3-D seismic

extension on Ras Abu Darag.

• Complete East Zeit exploratory well initiated in 2004.
• Drill 1 exploratory well on Southeast July.
• Drill 3 exploratory wells on North Zeit Bay.
• Drill 1 exploratory well on Southwest Gebel El Zeit.
Finalize agreement on Devon operated Gulf of Suez
•
South October block and Western Desert North Quaran
block.

• Key areas include Jackfish (100% interest), Dover (92%

• Solicit farmout and drill 1 exploratory well on block

interest) and Surmont (13% interest).

BM-BAR-3 in Brazil.

• Steam-Assisted Gravity Drainage (SAGD) is the primary

• Acquire 3-D seismic on blocks BM-C-30 and BM-C-32

D I S C O V E R I N G O U R F U L L P O T E N T I A L

SAGD technology

Jackfish to Tap
Canadian Oil Sands
I

n late 2004, Devon received final government
approval of its Jackfish thermal heavy oil project
in the oil sands of western Canada. The

Canadian oil sands are a vast oil resource with esti-
mated reserves second only to Saudi Arabia. Devon
will begin site preparation, construction and drilling
at Jackfish in the spring of 2005. We plan to begin
injecting steam underground in spring 2007, lead-
ing to first oil production later that year and full
production of 35,000 barrels per day in 2008.

Jackfish is owned 100 percent by Devon and
contains an estimated 300 million barrels of recov-
erable reserves. The site is located in northeastern
Alberta, near the town of Conklin. The tar-like
bitumen, deposited in the oil sands, cannot be
extracted by conventional oil production methods.
Shallow bitumen deposits are surface mined, but
the deeper Jackfish project will use steam-assisted
gravity drainage (SAGD) technology. The SAGD
process requires drilling parallel horizontal well
pairs. Each well pair includes an upper well through
which steam is injected and a lower well that deliv-
ers the liquefied bitumen to the surface, pressured
by the force of the steam.

At full production, each well pair is expected

to flow up to 1,000 barrels of oil per day to the sur-
face. Unlike conventional oil projects, SAGD wells
experience very little decline once production has
stabilized. Jackfish is expected to produce 35,000
barrels per day for 20 years or more.

Geological and operational risks are low, as

are capital costs per barrel. However, operating
costs are generally higher for SAGD projects than
for conventional projects. Natural gas fuels the
steam generators, requiring three-quarters to one
thousand cubic feet of gas for each barrel of bitu-
men produced.

Because of its heavy viscosity, bitumen must
be diluted with a lighter product before it can be
transported by pipeline. Depending upon market
conditions, Devon plans to dilute the Jackfish bitu-
men with synthetic crude, lighter oil or condensate.

D I S C O V E R I N G D E V O N
D I S C O V E R I N G D E V O N

17
17

Shown here are pipes carrying steam for injection and oil produced in a
Devon-operated thermal heavy oil project. Our Jackfish project will utilize
similar technology.

P
h
o
t
o

c
o
u
r
t
e
s
y

o
f

O
L
W
E
E
K
M
a
g
a
z
n
e

T
ouching
ives
of the environment. L

We embrace our
leadership role in the
communities where we
do business, and we strive
to be good stewards

18 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

D I S C O V E R I N G D E V O N

Touching Lives

At Devon, respect is a fundamental component of our operating culture: respect
for the health and safety of our employees, respect for the environment and
respect for the communities that we touch with our operations. As one of North
America’s largest independent oil and gas producers, we take our responsibilities
seriously and constantly strive to be good stewards and good neighbors.

Our contributions to youth and educa-
tion programs, health and human services
agencies, community outreach and cultural
projects make us a stronger company. This is
because healthy communities allow busi-
nesses to grow and prosper.

We promote conservation of the natural
environment and look for opportunities to
preserve wildlife habitat. Our continuing
efforts to reduce emissions have gained recog-
nition from the Environmental Protection
Agency (EPA). And our commitment to the
welfare of our employees is illustrated by workplace safety
records that consistently win accolades in the United States
and Canada.

At Devon, the safety of our employees, our respect for
the environment and our commitment to the communities
in which we operate are essential components of a corpo-
rate value system that places people, integrity and ethics at
its center.

E N V I R O N M E N TA L S T E WA R D S H I P

eeting the world’s growing demand for oil
and natural gas goes beyond the engineering,
geological, marketing and transportation
challenges we face each day. It is not enough
to find, produce and market oil and natural gas. As a con-
scientious steward in the areas in which we operate, we are
committed to work in ways that are compatible with the
natural environment.

At Devon, we are proud of our record of achievement.
We set high standards and embrace our leadership role in
the industry. Our stewardship initiatives are broad in scope.
Devon’s water conservation efforts in Wyoming won
accolades in 2004 from state and federal government agen-
cies. Our stature as an emissions reducer is among the

20 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

highest in the United States and Canada. We
seek opportunities to protect or restore habi-
tat and welcome partnerships with govern-
ment and private groups to achieve habitat
conservation objectives. Whether we are
reducing emissions, restoring habitat or lim-
iting the footprint our operations leave on
the landscape, we believe environmental
stewardship makes good business sense.

Air and Water Quality

Emissions reductions is an area where
Devon has demonstrated a commitment and desire to con-
tinue to grow as an industry leader. Since 1990, we have
been investing in more efficient production and trans-
portation technologies that reduce the volume of methane
released into the atmosphere.

In 2004, in the United States, those improvements
captured more than five billion cubic feet of natural gas
that would have been lost in the normal production and
transportation process. That is enough natural gas to heat
66,000 homes for an entire year. According to the EPA,
from an air quality perspective, our 2004 emission reduc-
tions are equal to planting more than 600,000 acres of
trees or taking 445,000 cars off the highway for a year.
Devon joined the EPA’s Natural Gas STAR program in
2003. Our advocacy and commitment as a first-year part-
ner in the voluntary emission reduction program resulted
in Devon being honored as Gas STAR’s 2004 “Rookie of
the Year.”

Our record of emissions reductions and reporting in
Canada is also among the best. Devon has obtained gold
reporting status through our partnership with the Voluntary
Challenge and Registry initiative. Under the program,
jointly sponsored by industry and government, Devon’s
Canadian operations reduced annual emissions by as much
as 650,000 metric tons of carbon dioxide equivalents.

Wildlife Habitat Conservation

We look for opportunities to restore or create wildlife
habitat both within and outside our operating venues. Our
projects have included participation in the national Rigs to
Reefs initiative in the Gulf of Mexico and our creation of
a refuge for the endangered whooping crane on the Texas
Gulf Coast.

In 2004, Devon donated 300 acres for a permanent
wildlife conservation easement in southern Arizona’s
Sonoran Desert. We teamed with a private developer and
the Tucson Audubon Society to initiate the project, and
then established an endowment to fund its long-term
maintenance. Under the restoration plan, Audubon
Society staff and volunteers are restoring native wildlife
habitat along a two-mile stretch of the Santa Cruz River.
The effort will ensure survival of a critical migratory link
for birds, deer, bears and other animals that depend on the
river as they move between mountain ranges.

Devon’s track record of operating in an environmen-
tally responsible manner has been recognized by various
governmental agencies. The U.S. Department of Interior’s
Bureau of Land Management recognized Devon’s cooper-
ation and conservation efforts in northern Wyoming’s Big
Horn Mountains with its 2004 Director’s Four C’s Award.
In addition, the Wyoming Game and Fish Department
honored Devon with its 2004 Industry Reclamation and
Wildlife Stewardship Award for water management and
habitat improvement in the state’s Powder River Basin.

Devon strives to conduct its field operations with the highest
regard for wildlife and their natural surroundings.

W O R K P L A C E S A F E T Y

evon’s operations begin and end with safety. If
we cannot do it safely, we do not do it. This phi-
losophy is illustrated by consistent recognition
from government agencies and industry associ-
ations in the United States and Canada. Whether we are
working in Wyoming’s Powder River Basin, Canada’s
Foothills or the Gulf of Mexico, our safety record consis-
tently wins recognition for excellence.

For the second year in a row, the Gas Processors
Association honored Devon with its President’s Award for
company-wide safety. The association also cited Devon’s
processing plants in Lone Camp, Texas, and Beaver Creek,
Wyoming, for outstanding safety records spanning 15
years without a lost-time injury.

In Canada, Devon was given the Best Safety
Performers award by the Occupational Health and Safety
Council. Devon was among 350 companies selected in
2004, from a pool of 110,000 companies in Alberta.

Devon’s offshore operations won two District Safety
Awards for Excellence in 2004 from the U.S. Department
of Interior’s Minerals Management Service. The agency
recognized Devon for its record of safety as well as its envi-
ronmental and regulatory stewardship.

D I S C O V E R I N G D E V O N

C O M M U N I T Y I N V O LV E M E N T

evon is a significant economic force in many of
our operating regions, and as such, we welcome
the opportunity to contribute to our communi-
ties. Volunteerism, funding and support for
local schools, agencies and projects are not auxiliary func-
tions for our company. Community involvement is a core
value at Devon. We understand that it is our responsibility
as a good corporate citizen to enhance the quality of life for
our employees, our families and our neighbors.

Devon’s spirit of outreach is broad and takes many
forms. Support for charitable agencies and community
projects through the United Way in the United States and
Canada is a fundamental part of our stewardship philoso-
phy. In 2004, Devon and its employees pledged nearly $1.5
million to United Way campaigns in Oklahoma City,
Houston, Calgary and other communities where Devon
has operations.

In rural communities where Devon operates, we sup-
port local law enforcement and crime prevention pro-
grams. We also support emergency response agencies and
education in these communities.

More than 200 employees at Devon’s headquarters
contribute their time to a weekly tutoring program for
inner-city grade-school children in Oklahoma City. Our

22 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

partnership with Mark Twain Elementary School has given
us an opportunity to make a difference in the lives of stu-
dents who face many disadvantages. In only the second
year of our partnership, Devon employees have made a
measurable contribution. Aided by the one-on-one tutor-
ing that students receive, the school has reported an
increase in reading and mathematics proficiency scores.
The Volunteer Center of Central Oklahoma recognized
Devon’s role at Mark Twain by honoring the company in
2004 with its Corporate Volunteer Group of the Year
award.

Devon has provided significant financial support to
higher education as well. The company pledged $1 million
in 2004 to Oklahoma City University’s Clara Luper
Scholarship Program for students from inner-city high
schools. Also in 2004, Devon pledged $10 million to the
University of Oklahoma. This gift will fund construction
of a research and teaching facility for the University’s
College of Engineering.

Our commitment to youth and education extends
beyond our corporate headquarters in Oklahoma City. In
Houston, Devon employees teach underprivileged middle
and high school students about personal finance, business
economics and success skills.

Students at Oklahoma City’s
Mark Twain Elementary
School are tutored by more
than 200 Devon volunteers.

Devon team members
Letty Hernandez and
Javier Saavedra prepare
for the 178-mile MS 150 Bike
Ride in Houston. The two-day
bike ride raises funds to
support the National MS
Society’s fight against
multiple sclerosis.

D I S C O V E R I N G D E V O N

T
ouching
ivesL

Devon also works with an inner-city elementary
school under Houston’s Communities in Schools program.
Volunteers speak during the school’s College Day, partici-
pate in the Chess Club, sponsor holiday parties and serve
as mentors and role models for at-risk students.

In Canada, we express our support for education in a
variety of ways. Our efforts include water stewardship pro-
grams for young people, advanced training for emergency
medical technicians and vocational instruction in aborigi-
nal communities.

Three years ago, Devon became the first corporate
sponsor of Trout Unlimited’s Yellow Fish Road Program.
This program raises awareness of water conservation and
management issues through projects in schools and youth
organizations. Since 1991, the program has given more
than 60,000 young people first-hand experience protect-
ing water quality by promoting conservation practices.

Devon also supports mobile education programs for
rural residents with limited access to learning opportuni-
ties. Devon’s support for the STARS Human Patient
Simulator Mobile Education Program recognizes the
importance of education and community health. The pro-

gram helps medical personnel in rural communities
sharpen their emergency medical skills through hands-on
training with a simulated human patient.

Devon is also a sponsor of the Northern Alberta
Institute of Technology Trades program for adult students
from aboriginal communities. The project provides stu-
dents with 21 weeks of academic upgrading and vocational
instruction needed to secure apprenticeships and careers in
a variety of trades.

Our commitment to youth and education is not con-
fined within the borders of North America. In Nigeria, we
invest $1 million annually for programs that send Nigerian
students to universities within their country as well as the
United States and Europe. Students study petroleum engi-
neering, geology, geophysics and other fields needed to
sustain the country’s growing petroleum industry.

In Cote d’Ivoire, Devon provides funding and
employee volunteer time at the Bingerville Orphanage,
home to more than 200 boys. We also support projects for
youth in Brazil and Egypt.

We are engaged in our communities around the
world because it is a social responsibility we embrace. Our
performance as a corporate citizen demonstrates who we
are as a company. n

The Devon-supported Bingerville Orphanage is home
to more than 200 boys in Cote d’Ivoire.

24 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

One of the children peeks from behind a toy distributed
during a recent visit to the orphanage.

Financial Statements and Management’s Discussion and Analysis

Financials

F E A T U R E S

Selected 11-Year Financial Data

28 Management’s Discussion and Analysis of

Financial Condition and Results of Operations

Report of Independent Registered Public
Accounting Firm

Consolidated Balance Sheets

57 Consolidated Statements of Operations

Consolidated Statements of Stockholders’ Equity
and Comprehensive Income (Loss)

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

100 Reports on Internal Control

102 Non-GAAP Financial Measures

Net Earnings
($ Millions)

Stockholders’
Equity
($ Billions)

Total Assets
($ Billions)

6
8
1
,
2

7
4
7
,
1

7
.
3
1

1
.
1
1

0
3
7

3
0
1

4
0
1

7
.
4

3
.
3

7
.
9
2 2
.
7
2

2
.
6
1

2
.
3
1

9
.
6

00 01 02 03 04

Devon earned a
record $2.2 billion
in 2004…

…increasing
stockholders’
equity 23% to
$13.7 billion...

...and driving total
assets to a record
$29.7 billion.

Touching Lives — PG16

Devon transferred its common stock listing to the
New York Stock Exchange in 2004.

D E V O N E N E R G Y C O R P O R A T I O N

• 2 0 0 4 A N N U A L R E P O R T

D I S C O V E R I N G D E V O N 25

Selected 11-Year Financial Data (1)

OPERATING RESULTS (In millions, except per share data)

Revenues (Net of royalties):

Oil sales
Gas sales
NGL sales
Marketing and midstream revenues
Other income

Total revenues

Production and operating expenses
Marketing and 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 stockholders
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

1994

1995

1996

1997

351
171
13
–
14

549

218
–

149
–
–
45
7
29
–
–
–
22
–
25

495

54
54
11
43

0.42
0.42

102
108

419
157
15
–
35

626

222
–

160
–
–
43
–
39
–
–
–
97
–
19

580

46
55
15
40

0.38
0.38

105
105

529
211
29
–
36

805

271
–

175
–
–
57
–
59
–
–
–
–
–
106

668

137
151
47
104

0.98
0.96

105
111

497
367
36
10
42

952

288
4

268
–
–
56
–
51
–
6
–
633
–
(128)

1,178

(226)
(218)
12
(230)

(1.67)
(1.67)

137
151

1,475

1,639

2,242

1,965

–
457
30
688
104

–
565
48
739
105

–
511
136
1,160
126

–
576
50
1,006
142

$
$

$
$
$
$

(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 since 2003. All periods have been adjusted to reﬂect the two-for-one stock split that occurred on November 15, 2004.

(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)

Includes distributions on preferred securities of subsidiary trust of $5, $10, $10 and $7 million in 1996, 1997, 1998 and 1999, respectively.
Before minority interest in Monterrey Resources, Inc. of ($1) and ($5) million in 1996 and 1997, respectively, and the cumulative effect of change in accounting principle of
$49 and $16 million in 2001 and 2003, respectively, and the results of discontinued operations of $9, $15, $13, ($35) $39, $69, $31 and $45 million in 1995 through 2002, respectively.

(5) Devon beneﬁcially owns 14.2 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.

26 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

ﬁ

1998

1999

2000

2001

2002

2003

2004

5-YEAR
COMPOUND

10-YEAR
COMPOUND
GROWTH RATE GROWTH RATE

236
335
25
8
22

626

231
3

212
–
–
48
13
53
–
16
–
354
–
(103)

827

(201)
(236)
-
(236)

(1.66)
(1.66)

142
154

436
616
68
20
10

1,150

328
10

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

906
1,474
154
53
40

2,627

544
28

662
–
41
96
60
155
–
3
–
–
–
377

784
1,878
131
71
69

2,933

666
47

831
–
34
114
1
220
–
11
2
979
–
5

909
2,133
275
999
34

4,350

886
808

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

1,588
3,897
407
1,460
37

7,389

1,282
1,174

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

2,202
4,732
554
1,701
103

9,292

1,535
1,339

2,290
44
–
277
–
475
–
(23)
62
–
–
1,107

1,343

1,966

2,910

4,291

5,658

7,106

(193)
(154)
4
(158)

(0.84)
(0.84)

187
199

661
730
10
720

2.83
2.75

255
263

23
103
10
93

0.37
0.36

255
259

59
104
10
94

0.31
0.30

309
313

1,731
1,747
10
1,737

4.16
4.04

417
433

2,186
2,186
10
2,176

4.51
4.38

482
499

1,931

6,096

6,860

13,184

16,225

27,162

29,736

–
885
15
750
142

760
1,656
313
2,521
253

760
1,289
634
3,277
257

649
5,940
2,149
3,259
252

662
6,900
2,627
4,653
314

677
7,903
4,370
11,056
472

692
6,339
4,800
13,674
484

38%
50%
52%
143%
59%

52%

36%
166%

43%
NM
NM
27%
NM
31%
NM
12%
NM
NM
NM
NM

40%

NM
NM
22%
NM

NM
NM

21%
20%

37%

(2%)
31%
73%
40%
14%

20%
39%
46%
NM
22%

33%

22%
NM

31%
NM
NM
20%
NM
32%
NM
NM
NM
NM
NM
46%

31%

45%
45%
(1%)
48%

27%
26%

17%
17%

35%

NM
30%
NM
35%
17%

D I S C O V E R I N G D E V O N 27

Management’s Discussion
and Analysis of Financial Condition and
Results

of Operations

OVERVIEW

ccording to most key ﬁnancial and operating measures, 2004 was the best year in Devon’s history. We delivered record
production, earnings, earnings per share and cash ﬂow from operations. Additionally, our drilling program was very successful.
We produced 251 million Boe in 2004, representing a 10% increase over our 2003 production of 228 million Boe. The
largest contributor to this growth was the merger with Ocean in April 2003. With four additional months of production in 2004,

the Ocean merger generated 21 million Boe of the year-over-year growth. Additionally, production in China began in the fourth quarter of
2003 and contributed seven million Boe of 2004 growth. These increases were partially offset by a decline in offshore Gulf of Mexico
production due to the effects of Hurricane Ivan and natural production declines on certain other properties.

In 2004, we also delivered the highest net earnings, $2.2 billion, and earnings per diluted share, $4.38, in our 16 years as a public

company. With an increase in production and increases in average realized commodity prices, Devon’s oil, gas and NGL revenues climbed
27% to almost $7.5 billion. Also contributing to the growth in earnings, our marketing and midstream margin grew 26% to $362 million
in 2004 primarily due to higher realized prices for natural gas and NGLs.

Record production and revenues were partially offset by higher operating expenses in 2004. The primary factors driving the increases
in expenses were increased operations due to the Ocean merger, increased well workover activity, the weakening of the U.S. dollar versus the
Canadian dollar and increased production taxes. The higher production taxes tracked our increase in commodity revenues. Although most
expenses increased, general and administrative expenses decreased 10% as a result of the realization of overhead and personnel efficiencies
following the Ocean merger.

In addition to generating record earnings in 2004, Devon also delivered record cash ﬂow from operations. At $4.8 billion, our
2004 cash ﬂow from operations represents a 28% increase over 2003. This all-time high amount was used to fund a $3.1 billion capital
expenditure program, $973 million of debt repayments, $189 million of common stock repurchases and $107 million of dividend
payments. At December 31, 2004, we had $2.1 billion of cash and short-term investments. This amount is adequate to cover debt
maturities through 2007.

Furthermore, on September 27, 2004, Devon announced two key initiatives aimed at creating additional value for its stockholders.
First, we announced a property divestiture program. The sales of non-core properties located in Canada, the onshore U.S. and in the Gulf of
Mexico are expected to generate $1.0 to $1.5 billion in after-tax proceeds. Closings are expected in the ﬁrst half of 2005. Second, we
announced a stock repurchase program. With cash ﬂow from operations and proceeds from the planned sales of oil and gas properties, we
intend to repurchase up to 50 million shares of our common stock. Through February 28, 2005, we had repurchased 12.5 million shares at a
total cost of $501 million.

In 2004, we declared a two-for-one stock split and moved our stock listing to the New York Stock Exchange. At its March 2005

meeting, Devon’s board of directors approved the increase of the quarterly cash dividends from $0.05 per share to $0.075 per share. The
increase is effective March 31, 2005.

Oil, gas and NGL prices and, therefore, oil, gas and NGL revenues are inﬂuenced by many factors outside of our control.

Consequently, 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. As a result, Devon has established a foundation of core assets in North America that can consistently deliver cost-
efficient drill-bit growth and provide a strong source of free cash ﬂow. We balance this foundation of core assets with measured investment in
high-impact projects in the deepwater Gulf of Mexico and international arenas.

28 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

During 2004, Devon drilled 274 exploration wells and over 1,900 development wells, and we incurred $2.9 billion in costs related to

oil and gas property acquisition, exploration and development activities. With an overall drilling success rate of 96%, reserves grew 268
million Boe from discoveries and extensions. Another 45 million Boe of reserves were added to Devon’s reserve base from performance
revisions. These 2004 drilling results are evidence of our success in lowering the costs of adding proved reserves.

At December 31, 2004, our proved reserves totaled 2.1 billion Boe. Although reserve additions due to discoveries, extensions and
performance revisions outpaced 2004 production, reserves at December 31, 2004 were relatively ﬂat compared to December 31, 2003. This
resulted from negative price revisions which reduced reserves by 76 million Boe.

To estimate reserves, accounting rules dictate that prices in effect as of the last day of the period are held constant indeﬁnitely. As a

result, two primary factors caused the negative price revisions at December 31, 2004. First, Devon’s reserves under certain international
production sharing contracts are based in part on the amount of revenue needed to recover our costs. Therefore, as prices increase, as was the
case for Brent prices at December 31, 2004 compared to December 31, 2003, our international reserves associated with production sharing
contracts decrease. Second, heavy oil differentials in Canada widened to over 54% of the NYMEX price at December 31, 2004 compared to
a historical average of approximately 30%. Both circumstances were the primary causes of the 2004 negative price revisions.

While Devon has consistently increased production over time, volatility in oil, gas and NGL prices has resulted in considerable
variability in earnings and cash ﬂows. Prices for oil, gas and NGLs are determined primarily by market conditions. Market conditions for
these products have been, and will continue to be, inﬂuenced by regional and worldwide economic activity, weather and other factors that
are beyond our control. Market conditions, among other factors, will continue to impact Devon’s future earnings and cash ﬂows.

Like all oil and gas exploration and production companies, Devon faces the challenge of natural production decline. As virgin reservoir
pressures are depleted, oil and natural 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, we have been able to overcome this natural
decline by adding, through drilling and acquisitions, more reserves than we produce. Devon’s future growth will depend on our ability to
continue to add reserves in excess of production.

In summary, 2004 was a successful year for Devon and its stockholders, and the outlook for 2005 is promising as well. Devon’s base of

core North American resources continues to deliver strong production growth, high margins and attractive returns. Our exploration
weighted activities in the Gulf of Mexico and in our international division will expose stockholders to meaningful value creation
opportunities. Devon’s ﬁnancial position provides the ﬂexibility to simultaneously invest in exploration and development projects, retire debt
and repurchase stock and, as was recently approved, increase cash dividends in 2005.

RESULTS OF OPERATIONS

Revenues

Changes in oil, gas and NGL production, prices and revenues from 2002 to 2004 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

2004

78
891
24
251

28.18
5.32
23.04
29.88

2,202
4,732
554
7,488

$
$
$
$

TOTAL
YEAR ENDED DECEMBER 31,
2003

2004 vs 2003 (2)

2003 vs 2002 (2)

+26%
+3%
+10%
+10%

+10%
+18%
+24%
+15%

+39%
+21%
+36%
+27%

62
863
22
228

25.63
4.51
18.65
25.88

1,588
3,897
407
5,892

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

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

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

2002

42
761
19
188

21.71
2.80
14.05
17.61

909
2,133
275
3,317

D I S C O V E R I N G D E V O N 29

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

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

2004

31
602
19
151

30.84
5.43
21.47
30.80

976
3,261
405
4,642

2004

14
279
5
65

21.60
5.15
29.23
28.80

299
1,437
143
1,879

2004

33
10
—
35

28.40
3.33
21.12
27.92

927
34
6
967

$
$
$
$

DOMESTIC
YEAR ENDED DECEMBER 31,
2003

2004 vs 2003 (2)

2003 vs 2002 (2)

+2%
+2%
+13%
+3%

+12%
+21%
+24%
+18%

+13%
+23%
+40%
+22%

31
589
17
146

27.64
4.50
17.31
26.02

861
2,652
289
3,802

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

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

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

CANADA
YEAR ENDED DECEMBER 31,
2003

2004 vs 2003 (2)

2003 vs 2002 (2)

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

-8%
+13%
+27%
+10%

-6%
+18%
+25%
+14%

14
267
5
63

23.54
4.57
23.08
26.25

318
1,222
114
1,654

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

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

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

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2003

2004 vs 2003 (2)

2003 vs 2002 (2)

+88%
+52%
N/M
+86%

+20%
-4%
-2%
+19%

+126%
+46%
+68%
+122%

17
7
—
19

23.64
3.47
21.45
23.45

409
23
4
436

+662%
N/M
N/M
+719%

+0%
N/M
N/M
-1%

+660%
N/M
N/M
+710%

2002

24
482
14
118

21.99
2.91
13.37
17.87

524
1,403
192
2,119

2002

16
279
5
68

21.00
2.62
15.93
16.96

331
730
83
1,144

2002

2
—
—
2

23.70
—
—
23.70

54
—
—
54

(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.
All percentage changes included in this table are based on actual ﬁgures and not the rounded ﬁgures included in this table.

(2)
N/M Not meaningful.

30 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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
2003

2004

2002

$
$
$
$

28.18
5.32
23.04
29.88

25.63
4.51
18.65
25.88

21.71
2.80
14.05
17.61

WITHOUT HEDGES
2003

2002

2004

35.99
5.39
23.04
32.60

27.67
4.79
18.65
27.48

22.63
2.70
14.05
17.36

Oil Revenues 2004 vs. 2003 Oil revenues increased $614 million in 2004. An increase in 2004 production of 16 million barrels caused
oil revenues to increase by $415 million. The April 2003 Ocean merger accounted for 14 million barrels of increased production. The remaining
increase is primarily related to new production from China partially offset by natural production declines and the effects of Hurricane Ivan on
Devon’s domestic properties. Oil revenues increased $199 million due to a $2.55 increase in the average realized price of oil.

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.

Gas Revenues 2004 vs. 2003 Gas revenues increased $835 million in 2004. A $0.81 per Mcf increase in the average gas price caused
revenues to increase by $714 million. An increase in 2004 production of 28 Bcf caused gas revenues to increase by $121 million. The April 2003
Ocean merger accounted for 43 Bcf of increased production. This was offset by a production decrease in Devon’s domestic properties as a result of
natural declines and the effects of Hurricane Ivan.

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.

NGL Revenues 2004 vs. 2003 NGL revenues increased $147 million in 2004. A $4.39 per barrel increase in average NGL prices caused

revenues to increase by $106 million. An increase in 2004 production of 2 million barrels caused revenues to increase $41 million. The April
2003 Ocean merger accounted for 0.6 million barrels of increased production. The remaining production increase was primarily related to new
drilling and development in the Barnett Shale properties.

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, 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.

Marketing and Midstream Revenues 2004 vs. 2003 Marketing and midstream revenues increased $241 million in 2004. Of this

increase, approximately $218 million was the result of higher overall market prices for natural gas and NGLs. Additionally, revenues increased
$103 million due to higher third-party natural gas and NGL throughput volumes. This was partially offset by $80 million in lower revenues
resulting primarily from the sale of certain assets in 2004.

2003 vs. 2002 Marketing and midstream revenues increased $461 million in 2003. Of this increase, approximately $439 million was the

result of higher overall market prices for natural gas and NGLs. Additionally, revenues increased $22 million due to higher third-party natural gas
and NGL throughput volumes. 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, partially offset by volumes lost as a
result of processing plant dispositions.

D I S C O V E R I N G D E V O N 31

Operating Costs and Expenses

The details of the changes in operating costs and expenses between 2002 and 2004 are shown in the table below.

2004

2004 vs 2003 (2)

2003

2003 vs 2002 (2)

2002

YEAR ENDED DECEMBER 31,

OPERATING COSTS AND EXPENSES ($ in millions):

Production and operating expenses:

Lease operating expenses
Production taxes

Total production and operating expenses

Depreciation, depletion and amortization of oil and gas properties
Accretion of asset retirement obligation

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
Production taxes

Total production and operating expenses

Depreciation, depletion and amortization of oil and gas properties
Accretion of asset retirement obligation

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

1,280
255
1,535
2,141
44
3,720
1,339
149
277
—
—
5,485

5.11
1.02
6.13
8.54
0.17
14.84
5.34
0.60
1.11
—
—
21.89

+19%
+25%
+19%
+28%
+21%
+25%
+14%
+19%
-10%
-100%
-100%
+16%

+8%
+13%
+9%
+17%
+10%
+13%
+4%
+9%
-18%
N/M
N/M
+6%

1,078
204
1,282
1,668
36
2,986
1,174
125
307
7
111
4,710

4.73
0.90
5.63
7.33
0.16
13.12
5.15
0.55
1.35
0.03
0.49
20.69

+39%
+84%
+45%
+51%
N/M
+50%
+45%
+19%
+40%
N/M
-83%
+25%

+15%
+53%
+20%
+25%
N/M
+24%
+20%
+0%
+16%
N/M
-86%
+3%

775
111
886
1,106
—
1,992
808
105
219
—
651
3,775

4.12
0.59
4.71
5.88
—
10.59
4.29
0.55
1.16
—
3.45
20.04

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)
N/M Not meaningful.

Oil, Gas and NGL Production and Operating Expenses 2004 vs. 2003 Lease operating expenses increased $202 million in 2004.
The April 2003 Ocean merger accounted for $84 million of the increase. Lease operating expenses on our historical properties increased $88
million, due to an increase in well workover expenses, ad valorem taxes and power, fuel, casualty insurance and repairs and maintenance
costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate resulted in a $30 million increase in costs.

The increase in lease operating expenses per Boe is primarily related to increased well workover expenses, ad valorem taxes and power,
fuel and repairs and maintenance costs, as well as the changes in the Canadian-to-U.S. dollar exchange rate. With the increase in oil, gas and
NGL prices, more well workovers and repairs and maintenance costs are performed to either maintain or improve production volumes. The
higher prices also resulted in increased power and fuel costs.

Production taxes increased $51 million in 2004. 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 22% increase in domestic
oil, gas and NGL revenues was the primary cause of the production tax increase.

2003 vs. 2002 Lease operating expenses increased $303 million in 2003. The April 2003 Ocean merger accounted for $199 million of

the increase. Lease operating expenses on our historical properties increased $120 million, due to an increase in well workover expenses and
power, fuel, casualty insurance and repairs and maintenance costs. Additionally, changes in the Canadian-to-U.S. dollar exchange rate
resulted in a $44 million increase in costs. These increases were partially offset by a decrease of $60 million due to property divestitures in
2002.

The increase in lease operating expenses per Boe is primarily related to increased well workover expenses and power, fuel and repairs
and maintenance costs, as well as the changes in the Canadian-to-U.S. dollar exchange rate. With the increase in oil, gas and NGL prices,
more well workovers and repairs and maintenance costs are performed to either maintain or improve production volumes. The higher prices
also resulted in increased power and fuel costs.

As stated previously, most U.S. production taxes are based on a ﬁxed percentage of revenues. Therefore, the 79% increase in domestic

oil, gas and NGL revenues was the primary cause of the $93 million production tax increase.

32 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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.

2004 vs. 2003 Oil and gas property related DD&A increased $473 million in 2004. An increase in the combined U.S., Canadian and
international DD&A rate from $7.33 per BOE in 2003 to $8.54 per BOE in 2004 caused oil and gas property related DD&A to increase by
$305 million. The increase in the DD&A rate is primarily related to the April 2003 Ocean merger, negative reserve revisions in Canada and
certain international countries subject to production sharing contracts and changes in the Canadian-to-U.S. dollar exchange rate. A 10% increase
in 2004 oil, gas and NGL production caused DD&A to increase $168 million.

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 NGL production caused DD&A to increase $231 million.

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

(“SFAS”) No. 143, Accounting for Asset Retirement Obligations, 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. We recorded $44 million and $36 million of such accretion expense during
2004 and 2003, respectively.

Marketing and Midstream Operating Costs and Expenses 2004 vs. 2003 Marketing and midstream operating costs and expenses

increased $165 million in 2004. Of this increase, approximately $133 million was the result of an increase in prices paid for gas and NGLs.
Additionally, operating costs and expenses increased $106 million due to higher third-party natural gas and NGL throughput volumes. This was
partially offset by $74 million in lower costs and expenses resulting primarily from the sale of certain assets in 2004.

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, partially offset by
volumes lost as a result of processing plant dispositions.

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 related to exploration and development activities. 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.

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

Net G&A

2004

2004 vs 2003

2003

2003 vs 2002

2002

YEAR ENDED DECEMBER 31,

($ IN MILLIONS)

549
(172)
(100)
277

+5%
+22%
+29%
-10%

524
(140)
(77)
307

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

387
(97)
(71)
219

D I S C O V E R I N G D E V O N 33

2004 vs. 2003 Gross G&A increased $25 million. The April 2003 Ocean merger increased gross expenses $27 million primarily

due to the inclusion of an additional four months of Ocean activities in 2004 compared to 2003. Also, higher compensation and beneﬁt
costs, increased charitable contributions and the abandonment of certain Canadian office space increased gross G&A $26 million, $12
million and $5 million, respectively. During 2004, Devon also incurred $6 million of incremental professional fees related to additional
activities performed to comply with the requirements of Section 404 of The Sarbanes-Oxley Act of 2002. Finally, changes in the
Canadian-to-U.S. dollar exchange rate resulted in a $8 million increase in costs. These increases were partially offset by the synergies
obtained from the Ocean merger.

The increase in both capitalized G&A of $32 million and reimbursed G&A of $23 million was primarily related to the increased

activity subsequent to the April 2003 Ocean merger.

2003 vs. 2002 Gross G&A increased $137 million. This increase was primarily related to the 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 $14 million 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 was primarily related to the April 2003 Ocean merger, partially offset by a decline in
reimbursements related to the 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, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated
after-tax future net revenues from proved oil and gas properties, excluding future cash outﬂows associated with settling asset retirement
obligations included in the net book value of 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 used are those as of the end of the appropriate quarterly period. These prices
are not changed except where different prices are ﬁxed and determinable from applicable contracts for the remaining term of those contracts.
Devon has entered into various derivative instruments that are accounted for as cash ﬂow hedges. These instruments, which consist of price
swaps and costless price collars, and the related future production volumes, are discussed in Note 12. The effect of these hedges has been
considered in calculating the full cost ceiling limitations as of December 31, 2004. These hedges reduced the full cost ceiling limitations for
the United States, Canada and Equatorial Guinea as of the end of 2004 by $102 million, $77 million and $76 million, respectively.
However, the 2004 capitalized costs in these countries did not exceed the related ceiling limitations, with or without the effects of the hedges.
The calculation also dictates the use of a 10% discount factor. The costs to be recovered are compared to the ceiling on a quarterly
basis. If the costs to be recovered exceed the ceiling, the excess is written off as an expense, except as discussed in the following paragraph.

If, subsequent to the end of the quarter but prior to the applicable ﬁnancial statements being published, prices increase to levels such

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

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. We estimate such fair value using our estimates of future oil, gas and NGL prices. In contrast, the ceiling
calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indeﬁnitely. Accordingly, the resulting
value 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 even though higher oil and gas prices may have

increased the ceiling applicable to the subsequent period.

During 2003 and 2002, we reduced the carrying value of our oil and gas properties by $68 million and $651 million, respectively, due

to the full cost ceiling limitations. The after-tax effects of these reductions in 2003 and 2002 were $36 million and $371 million,
respectively. The following table summarizes these reductions by geographic area.

YEAR ENDED DECEMBER 31,

2003

GROSS

NET OF
TAXES

2002

GROSS

NET OF
TAXES

(IN MILLIONS)

—
68
68

—
36
36

651
—
651

371
—
371

Canada
International
Total

34 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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, our 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 our 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, we 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, we determined that these properties did not
meet our internal criteria to justify further investment. Accordingly, we 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 our second quarter results. However, this increase
was not sufficient to offset the entire reduction calculated as of June 30.

Other Income (Expenses)

The details of the changes in other income (expenses) between 2002 and 2004 are shown in the table below.

Other income (expenses):

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 derivative ﬁnancial instruments
Impairment of ChevronTexaco Corporation common stock
Other income
Total

YEAR ENDED DECEMBER 31,

2004

(513)
(2)
(2)
(22)
70
—
(6)
(475)
—
23
(62)
—
103
(411)

2003
(IN MILLIONS)

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

2002

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

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

Interest Expense 2004 vs. 2003 The average debt balance outstanding decreased from $8.9 billion in 2003 to $8.5 billion in 2004

causing interest expense to decrease $21 million. The decrease in average debt outstanding was due to debt repayments during 2004. The
average interest rate on outstanding debt was approximately 6.0% in both periods. However, a slightly higher rate in 2004 caused interest
expense to increase $3 million.

Other items included in interest expense that are not related to the debt balance outstanding were $9 million lower in 2004. Of this

decrease, $20 million related to the capitalization of interest. The increase in interest capitalized was primarily related to additional unproved
properties acquired from the April 2003 Ocean merger and the nature of the properties acquired. The Ocean properties included signiﬁcant
deepwater Gulf and international exploratory properties and major development projects. The effect of the $20 million increase in
capitalized interest was partially offset by $16 million of debt issuance costs expensed in 2004. The $16 million related to the early
repayment of the outstanding balance under the $3 billion term loan credit facility in the second quarter of 2004.

D I S C O V E R I N G D E V O N 35

2003 vs. 2002 The average debt balance outstanding increased from $8.3 billion in 2002 to $8.9 billion in 2003 causing interest

expense to increase $32 million. The increase in average debt outstanding was attributable primarily to the debt assumed as a result of 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 the capitalization of interest, $10 million related to lower net accretion and $8 million related to the loss on
the early extinguishment of the 8.75% senior notes in 2002. The increase in interest capitalized was primarily related to additional unproved
properties acquired from the April 2003 Ocean merger.

Effects of Changes in Foreign Currency Exchange Rates Our Canadian subsidiary, which has designated the Canadian dollar

as its functional currency, has certain 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 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 which 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 $0.7738 at December 31, 2003 to $0.8308 at
December 31, 2004 resulted in a $22 million gain. 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.

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 14.2 million shares of ChevronTexaco common stock. We acquired these
shares in the August 1999 acquisition of PennzEnergy Company. The shares are deposited with an exchange agent for possible exchange for
$760 million of debentures that are exchangeable into the ChevronTexaco shares. The debentures, which mature in August 2008, were also
assumed by Devon in the 1999 PennzEnergy acquisition.

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

was $47.69 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 our 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 $44.25 at June 30, 2002, to $34.63 per share at September 30, 2002, and to $33.24 per share at December 31, 2002. The year-end
price of $33.24 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 our net earnings by $128 million.

The share price of ChevronTexaco common stock has increased to $43.19 at December 31, 2003 and $52.51 at December 31,
2004. As a result, the market value of Devon’s investment in ChevronTexaco common stock increased $273 million from December 31,
2002 to December 31, 2004. 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 we determine that such declines
are other than temporary.

Other Income 2004 vs. 2003 Other income increased $66 million in 2004. Other income increased $37 million due to gains
resulting from sales of certain non-oil and gas properties in 2004. Interest and dividend income increased $12 million in 2004 due to an
increase in cash and short-term investment balances.

36 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Income Taxes

2004 vs. 2003 Devon’s 2004 effective ﬁnancial tax rate attributable to continuing operations was an expense of 34% compared to an
expense of 23% in 2003. Both the 2004 and 2003 rates beneﬁted from Canadian statutory rate reductions. These rate reductions resulted in
a $36 million and $218 million beneﬁt being recorded in 2004 and 2003, respectively, related to the lower tax rates being applied to deferred
tax liabilities outstanding as of the beginning of the year. Excluding the effects of the Canadian rate reductions in 2004 and 2003 and the
reduction of carrying value of oil and gas properties in 2003, the effective ﬁnancial tax expense rates were 35% and 33% in 2004 and 2003,
respectively. The 2004 rate was equal to the statutory federal tax rate primarily due to the effect of state income taxes offset by the tax
beneﬁts of certain foreign deductions. The 2003 rate was lower than the statutory federal tax rate primarily due to the tax beneﬁts of certain
foreign deductions.

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. 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.

Results of Discontinued Operations

On April 18, 2002, we sold our 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, we reclassiﬁed our Indonesian, Argentine and Egyptian activities as discontinued operations. This reclassiﬁcation affects not

only the 2002 presentation of ﬁnancial results, but also the presentation of all prior periods’ results. Subsequent to the sale of our Egyptian
and Indonesian operations, we 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 both 2003 and 2004.

Following are the components of the net results of discontinued operations for the year 2002.

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

(IN MILLIONS)
31
23
9
45

Cumulative Effect of Change in Accounting Principle

Effective January 1, 2003, we 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.

In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106 to provide guidance regarding the interaction of SFAS

No. 143 with the full cost method of accounting for oil and gas properties. Speciﬁcally, SAB No. 106 clariﬁes the manner in which the full
cost ceiling test and DD&A should be calculated in accordance with the provisions of SFAS No. 143. We adopted SAB No. 106 in the
fourth quarter of 2004. However, this adoption did not materially impact our full cost ceiling test calculation or DD&A for 2004.

CAPITAL RESOURCES AND LIQUIDITY

The following discussion of liquidity and capital resources should be read in conjunction with the consolidated ﬁnancial statements

included elsewhere in this report.

Sources and Uses of Cash

Cash provided by (used in):

Operating activities
Investing activities
Financing activities

Effect of exchange rate changes
Net increase in cash and cash equivalents
Cash and cash equivalents at end of year
Short-term investments at end of year

2004

2003
(IN MILLIONS)

2002

4,816
(3,634)
(1,001)
39
220
1,152
967

3,768
(2,773)
(414)
59
640
932
341

1,754
(2,046)
401
—
109
292
—

$
$
$

D I S C O V E R I N G D E V O N 37

Cash Flows from Operating Activities Net cash provided by operating activities (“operating cash ﬂow”) continued to be a
primary source of capital and liquidity in 2004. Operating cash ﬂow in 2004 was $4.8 billion compared to $3.8 billion in 2003 and $1.8
billion in 2002. The increases in operating cash ﬂow in 2004 and 2003 were primarily caused by the increases in revenues, partially offset by
increased expenses, as discussed in the “Results of Operations” section of this report.

Cash Flows from Investing Activities Net cash used in investing activities was $3.6 billion in 2004 compared to $2.8 billion in
2003 and $2.0 billion in 2002. The increases in cash used in investing activities were directly related to increased capital expenditures net
of proceeds from the sale of property and equipment, as well as increases in short-term investment balances of $626 million and $341
million in 2004 and 2003, respectively.

Capital expenditures in 2004 were $3.1 billion. This total includes $3.0 billion for the acquisition, drilling or development of oil and

gas properties. These amounts compare to capital expenditures of $2.6 billion in 2003 and $3.4 billion in 2002. The 2003 amount included
$2.5 billion for the acquisition, drilling or development of oil and gas properties. The 2002 amount 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 April 2003 Ocean merger did not affect 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. As a result,
the Mitchell merger did have an impact on capital expenditures paid in cash.

Proceeds from sales of property and equipment were $95 million, $179 million and $1.4 billion in 2004, 2003 and 2002, respectively.

The 2002 amount includes proceeds from the sales of certain non-core oil and gas properties which were used to pay down debt.

Cash Flows from Financing Activities Net cash used in ﬁnancing activities during 2004 was $1.0 billion compared to $414
million in 2003. The increase in cash used in ﬁnancing activities from 2003 to 2004 was directly related to increased debt repayments net of
borrowings. The increase was also related to increased common stock dividends and the repurchase of common stock, partially offset by an
increase in proceeds from the issuance of common stock. Net cash provided by ﬁnancing activities was $401 million in 2002, consisting
primarily of net proceeds from borrowings of long-term debt.

During 2004, Devon retired $973 million of debt. This was primarily related to the $211 million 6.75% notes due February 15, 2004
and the $125 million 8.05% notes due June 15, 2004, and payment of the remaining $635 million outstanding on the $3 billion term loan
credit facility. During 2003, principal payments on long-term debt, net of proceeds from borrowings of long-term debt, were $521 million.
This net amount related to long-term debt assumed in the April 2003 Ocean merger.

During 2002, Devon had net borrowings of $410 million. These net borrowings were primarily related to the $2 billion borrowed
under the $3 billion term loan credit facility to pay for the cash portion of the Mitchell merger. This was partially offset primarily by the
repayment of $1.1 billion of this facility with proceeds from the 2002 property sales, the early retirement of the 8.75% notes due June
15, 2007 and certain Canadian notes, and the retirement of Devon’s outstanding borrowings under its commercial paper and revolving
credit facilities.

Devon’s common stock dividends were $97 million, $39 million and $31 million in 2004, 2003 and 2002, respectively. We also paid

$10 million of preferred stock dividends in 2004, 2003 and 2002. The increase in common stock dividends from 2003 to 2004 was
primarily related to a 100% increase in the quarterly dividend rate and the increased number of shares outstanding. Effective with the ﬁrst
quarter 2004 dividend payment, Devon increased its quarterly dividend rate from $0.025 per share to $0.05 per share. The increase in shares
outstanding was primarily related to the April 2003 Ocean merger.

In conjunction with the stock buyback program announced September 27, 2004, Devon repurchased 5 million shares at a total cost of

$189 million during 2004.

Devon received $268 million, $155 million and $32 million from shares issued for employee stock options exercised during 2004,

2003 and 2002, respectively.

Liquidity

At December 31, 2004, Devon’s unrestricted cash and cash equivalents and short-term investments totaled $2.1 billion. During 2004,

2003 and 2002, such balances increased $846 million, $981 million and $109 million, respectively.

Historically, Devon’s primary source of capital and liquidity has been operating cash ﬂow. Additionally, we maintain a revolving line of

credit and a commercial paper program which can be accessed as needed to supplement operating cash ﬂow. Other available sources of
capital and liquidity include the issuance of equity securities and long-term debt. Over the next 12 months, another major source of liquidity
will be proceeds from the sales of oil and gas properties as announced September 27, 2004. After-tax sale proceeds from the divestiture
program are expected to range between $1.0 billion and $1.5 billion. We expect the combination of these sources of capital will be more
than adequate to fund future capital expenditures, the common stock buyback program, and other contractual commitments as discussed
later in this section.

38 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Operating Cash Flow Devon’s operating cash ﬂow is sensitive to many variables, the most volatile of which is pricing of the oil,

natural gas and NGLs produced. Prices for these commodities are determined primarily by prevailing market conditions. Regional and
worldwide economic activity, weather and other substantially variable factors inﬂuence market conditions for these products. These factors
are beyond our control and are difficult to predict.

To mitigate some of the risk inherent in oil and natural gas prices, Devon has utilized price collars to set minimum and maximum

prices on a portion of its 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, 2004.

Oil production (MMBbls)

2005

Natural gas production (Bcf )

2005
2006

PRICE
COLLARS

PRICE SWAP
CONTRACTS

FIXED-PRICE PHYSICAL
DELIVERY CONTRACTS

TOTAL

35
—

3
—

—

18
18

56
18

In addition to the above quantities, we have ﬁxed-price physical delivery contracts covering Canadian natural gas production for the

years 2007 through 2011 ranging from 8 Bcf to 14 Bcf per year. Also, Devon has a ﬁxed-price physical delivery contract covering 4 Bcf and
3 Bcf of International natural gas production in 2007 and 2008, respectively. From 2012 through 2016, we have Canadian natural gas
volumes subject to ﬁxed-price contracts, but the yearly volumes are less than 1 Bcf.

It is our policy to only enter into derivative contracts with investment grade rated counterparties deemed by management as competent

and competitive market makers. Devon does not hold or issue derivative instruments for speculative trading purposes.

Credit Lines Another source of liquidity is our $1.5 billion ﬁve-year, syndicated, unsecured revolving line of credit (the “Senior
Credit Facility”). The Senior Credit Facility includes (i) a ﬁve-year revolving Canadian subfacility in a maximum amount of U.S. $500
million and (ii) a $1 billion sublimit for the issuance of letters of credit, including letters of credit under the Canadian subfacility.

The Senior Credit Facility matures on April 8, 2009, and all amounts outstanding will be due and payable at that time unless the

maturity is extended. Prior to each April 8 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for
one year, subject to the approval of the lenders. Devon has obtained lender approval to extend the current maturity date of April 8, 2009 to
April 8, 2010. This maturity date extension will be effective April 8, 2005, provided Devon has not experienced a “material adverse effect,”
as deﬁned in the Senior Credit Facility agreement at that date.

Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various ﬁxed rate options for periods of up to

12 months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The Senior Credit Facility
currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.

As of December 31, 2004, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit

Facility as of December 31, 2004, net of $226 million of outstanding letters of credit, was approximately $1.3 billion.

The Senior Credit Facility contains 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 agreement contains deﬁnitions of total funded debt and total
capitalization that include adjustments to the respective amounts reported in Devon’s consolidated ﬁnancial statements. Per the agreement,
total funded debt excludes the debentures that are exchangeable into shares of ChevronTexaco Corporation common stock. Also, total
capitalization is adjusted to add back noncash ﬁnancial writedowns such as full cost ceiling property impairments or goodwill impairments.
As of December 31, 2004, Devon’s ratio as calculated pursuant to this covenant was 33.0%.

Our access to funds from the Senior Credit Facility 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
business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit
agreement. While our Senior Credit Facility includes 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 Senior Credit Facility is not conditioned on the absence of a material adverse effect.
We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program
may not exceed $725 million. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit
Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between seven to 90 days, although it can have a
maturity of up to 365 days. We had no commercial paper debt outstanding at December 31, 2004.

D I S C O V E R I N G D E V O N 39

Debt Ratings Devon receives debt ratings from the major ratings agencies in the United States. In determining our 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 and capital allocation challenges. Liquidity, asset quality, cost structure, reserve mix and commodity pricing levels are
also considered by the rating agencies.

Devon’s current debt ratings are BBB with a stable outlook by Standard & Poor’s, Baa2 with a stable outlook by Moody’s and BBB
with a stable outlook by Fitch. There are no “rating triggers” in any of our contractual obligations that would accelerate scheduled maturities
should our debt rating fall below a speciﬁed level. Certain of Devon’s agreements related to its oil and natural gas hedges do contain
provisions that could require us to provide cash collateral in situations where our liability under the hedge is above a certain dollar threshold
and where our debt rating is below investment grade (BBB- or Baa3). However, Devon’s liability under these agreements would only exceed
the threshold level in circumstances where the market prices for oil or natural gas were rising. It is unlikely that our 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 our Senior Credit Facility is predicated on its corporate debt rating. Therefore, even though a ratings
downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit
Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs for the Senior
Credit Facility from LIBOR plus 70 basis points to a new rate of LIBOR plus 87.5 basis points. A ratings downgrade could also adversely
impact our ability to economically access future debt markets.

As of December 31, 2004, we are not aware of any potential ratings downgrades being contemplated by the rating agencies.

Capital Expenditures In February 2005, Devon announced its 2005 capital expenditures budget. Our 2005 capital expenditures

are expected to range from $3.0 billion to $3.5 billion, representing the largest planned use of capital resources for capital investment
activities. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if oil and natural gas prices
ﬂuctuate from current estimates, we could choose to defer a portion of these planned 2005 capital expenditures until later periods or
accelerate capital expenditures planned for periods beyond 2005 to achieve the desired balance between sources and uses of liquidity. Based
upon current oil and natural gas price expectations for 2005, we anticipate that our capital resources will be more than adequate to fund
2005 capital expenditures.

Common Stock Buyback Program During 2004 Devon repurchased ﬁve million shares of its common stock, and we intend to
repurchase up to 45 million additional shares in 2005 in conjunction with a stock buyback program announced in September 2004. The
shares will be repurchased with operating cash ﬂow and proceeds from the planned sales of oil and gas properties announced on September
27, 2004. The stock repurchase program may be discontinued at any time.

Contractual Obligations A summary of Devon’s contractual obligations as of December 31, 2004, is provided in the following table.

Long-term debt
Interest expense
Asset retirement obligations
Drilling and facility obligations
Firm transportation agreements
Operating leases:

Office and equipment leases
Spar leases
FPSO leases

Other

Total

PAYMENTS DUE BY YEAR

2005

2006

2007

2008
(IN MILLIONS)

2009

AFTER
2009

TOTAL

926
506
46
409
91

35
15
20
7
2,055

667
470
59
132
70

30
15
20
6
1,469

400
444
52
4
60

28
15
20
5
1,028

761
426
61
16
47

25
15
19
5
1,375

177
390
69
3
35

23
14
13
3
727

5,025
4,582
452
5
145

69
228
—
1

10,507

7,956
6,818
739
569
448

210
302
92
27
17,161

Firm transportation agreements represent “ship or pay” arrangements whereby we have committed to ship certain volumes of oil, gas

and NGLs for a ﬁxed transportation fee. We have entered into these agreements to aid the movement of our gas production to market.
Devon has sufficient production to utilize the majority of these transportation services.

40 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Devon has two offshore platform spars that 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 we may purchase the lessors’ interests in the spars.
We have 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.

We also have two ﬂoating, production, storage and offloading facilities (“FPSO”) that are being leased under operating lease

arrangements. One FPSO is being used in the Panyu project offshore China. 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 2009.

The above table does not include $226 million of letters of credit that have been issued by commercial banks on Devon’s behalf. These
letters of credit, if funded, would become borrowings under our revolving credit facility. Most of these letters of credit have been granted by
Devon’s ﬁnancial institutions to support our international and Canadian drilling commitments. The $8 billion of long-term debt shown in
the table excludes $1 million of net discounts and a $9 million fair value adjustment. Both of these items are included in the December 31,
2004, book balance of the debt.

Pension Funding and Obligations Devon’s pension expense is recognized on an accrual basis over employees’ approximate service
periods and is generally calculated independent of funding decisions or requirements. We recognized expense for our deﬁned beneﬁt pension
plans of $26 million, $35 million and $16 million in 2004, 2003 and 2002, respectively. We estimate that our pension expense will
approximate $26 million in 2005.

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

$132 million and $137 million at December 31, 2004 and 2003, respectively. The decrease in the underfunded amount during 2004 was
primarily caused by gains on investments and $70 million of cash contributions made to the plans by Devon. These were partially offset by
increases in the beneﬁt obligations. A detailed reconciliation of the 2004 activity is included in Note 13 to the accompanying consolidated
ﬁnancial statements. Of the $132 million underfunded status at the end of 2004, $109 million is attributable to various nonqualiﬁed
deﬁned beneﬁt plans which have no plan assets. However, we have established certain trusts to fund the beneﬁt obligations of such
nonqualiﬁed plans. As of December 31, 2004, these trusts had investments with a market value of $60 million. The value of these trusts is
included in noncurrent other assets in our accompanying consolidated balance sheets.

As compared to the “accumulated beneﬁt obligation,” our qualiﬁed deﬁned beneﬁt plans were overfunded by $11 million at December
31, 2004. The accumulated beneﬁt obligation differs from the projected beneﬁt obligation in that the former includes no assumption about
future compensation levels. Our current intentions are to provide sufficient funding in future years to ensure the accumulated beneﬁt
obligation remains fully funded. The actual amount of contributions required during this period will depend on investment returns from the
plan assets. Required contributions also depend upon changes in actuarial assumptions made during the same period, particularly the
discount rate used to calculate the present value of the accumulated beneﬁt obligation. For 2005, Devon expects its contributions to the plan
to be less than $10 million.

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.

We assumed that our plan assets would generate a long-term weighted average rate of return of 8.34% and 8.25% at December 31,

2004 and 2003, 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.

We believe that our long-term asset allocation on average will approximate the targeted allocation. We regularly review our actual asset

allocation and periodically rebalance 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 our long-term rate of return assumption

of 100 basis points (from 8.34% to 7.34%) would increase the expected 2005 pension expense by approximately $4 million.

Devon discounted its future pension obligations using a weighted average rate of 5.74% at December 31, 2004, compared to 6.23% at

December 31, 2003. 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. We consider 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 5.74% to 5.49%) would increase our pension liability at December 31, 2004, by approximately $18 million, and increase
estimated 2005 pension expense by approximately $2 million.

D I S C O V E R I N G D E V O N 41

At December 31, 2004, Devon had unrecognized actuarial losses of $155 million. These losses will be recognized as a component of

pension expense in future years. We estimate that approximately $9 million and $8 million of the unrecognized actuarial losses will be
included in pension expense in 2005 and 2006, respectively. The $9 million estimated to be recognized in 2005 is a component of the total
estimated 2005 pension expense of $26 million referred to earlier in this discussion.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Devon’s deﬁned
beneﬁt pension plans will impact future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Full Cost Ceiling Calculations

We follow the full cost method of accounting for our 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. The ceiling limitation is the
discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outﬂows associated with settling
asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. If
Devon’s capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense. The ceiling limitation is imposed
separately for each country in which we have oil and gas properties.

The discounted present value of future net revenues for our 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 our reserve estimates are prepared by outside
petroleum 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 ﬁve years, annual revisions to our reserve estimates, which have been both increases and decreases in
individual years, 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 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. Rather, 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. This adjustment requires little judgment as the end-of-period price is
adjusted using the contract prices for our cash ﬂow hedges.

The ceiling calculation also dictates that a 10% discount factor is to be used to calculate the present value of net cash ﬂows.
Because the ceiling calculation dictates that prices in effect as of the last day of the applicable quarter are held constant indeﬁnitely, and

requires a 10% discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have
historically been cyclical. On any particular day at the end of a quarter, prices can be either substantially higher or lower than Devon’s long-
term price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost
ceiling limitation, and that are caused by ﬂuctuations in price as opposed to reductions to the underlying quantities of reserves, should not be
viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Derivative Financial Instruments

Devon enters into oil and gas derivative 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. We are not involved in any speculative trading
activities of derivatives. All derivatives requiring balance sheet recognition are recognized on the balance sheet at their fair value.

A substantial portion of our 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. 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 attributable to the effective portion of
these hedging instruments are not included in our consolidated results of operations. Instead, the changes in fair value of the effective
portion of these hedging instruments, net of tax, are recorded directly to stockholders’ equity until the hedged oil or natural gas quantities are

42 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

produced. The ineffective portion of these hedging instruments is included in our consolidated results of operations.

To qualify for hedge accounting treatment, we designate our 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, we document all relationships
between hedging instruments and hedged items, as well as our 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 we fail 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 LIBOR and money market futures rates for the ﬁrst year and money market futures and
swap rates thereafter. In addition, we estimate the option value of price ﬂoors and price caps using an option pricing model. These pricing
and discounting variables are sensitive to the period of the contract and 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.

Quarterly changes in estimates of fair value have only a minimal impact on our liquidity, capital resources or results of operations, as

long as the derivative contracts qualify for treatment as a hedge. However, settlements of derivative contracts do have an impact on our
liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative contracts, our net earnings and
cash ﬂow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true.
Additional information regarding the effects that changes in market prices will have on our derivative ﬁnancial instruments, net earnings and
cash ﬂow from operations is included in the “Quantitative and Qualitative Disclosures about Market Risk” section of this report.

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, and recent accounting pronouncements require that all
future acquisitions will be accounted for using the purchase method.

Under the purchase method, the acquiring company adds to its balance sheet the estimated fair values of the acquired company’s assets

and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill.
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, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work
performed by our 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 end-of-period 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 our estimates of future oil, natural gas and NGL prices. Devon’s 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.

We estimate future prices to apply to the estimated reserve quantities acquired, and 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 we consider 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, and this debt must be recorded at the estimated fair value as if Devon had issued such debt. However, signiﬁcant judgment

D I S C O V E R I N G D E V O N 43

on our behalf is usually not required in these situations due to the existence of comparable market values of debt issued by 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 Mitchell’s 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 from Mitchell. Therefore,

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, we also estimated future operating and capital costs of the marketing and midstream assets to arrive at
estimated future cash ﬂows. These cash ﬂows were discounted at rates consistent with those used to discount future net cash ﬂows from oil
and gas producing assets to arrive at our estimated fair value of the marketing and midstream facilities and equipment.

In addition to the valuation methods described above, Devon performs other quantitative analysis 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 companies analysis, we review the public stock market trading multiples for selected publicly traded independent

exploration and production companies with comparable ﬁnancial and operating characteristics. Such characteristics are market
capitalization, location of proved reserves and the characterization of those reserves that we deem 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.

In a comparable transactions analysis, we review 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, we use 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.

While these estimates of fair value for the various assets acquired and liabilities assumed have no effect on Devon’s liquidity or capital

resources, they can have an effect on the future results of operations. Generally, the higher the fair value assigned to both the oil and gas
properties and non-oil and gas properties, the lower future net earnings will be as a result of higher future depreciation, depletion and
amortization expense. Also, a higher fair value assigned to the oil and gas properties, based on higher future estimates of oil and gas prices,
will increase the likelihood of a full cost ceiling writedown in the event that subsequent oil and gas prices drop below Devon’s price forecast
that was used to originally determine fair value. A full cost ceiling writedown would have no effect on liquidity or capital resources in that
period. However, it would adversely affect our future results of operations. The full cost ceiling writedown is a noncash charge. As discussed
in the “Capital Resources and Liquidity” section, in calculating our debt-to-capitalization ratio under our credit agreement, total
capitalization is adjusted to add back noncash ﬁnancial writedowns such as full cost ceiling property impairments or goodwill impairments.
Our estimates of reserve quantities are one of the many estimates that are involved in determining the appropriate fair value of the oil
and gas properties acquired in a business combination. As previously disclosed in our discussion of the full cost ceiling calculations, during
the past ﬁve years, Devon’s annual revisions to its reserve estimates have averaged approximately 2%. As discussed in the preceding
paragraphs, there are numerous estimates in addition to reserve quantity estimates that are involved in determining the fair value of oil and
gas properties acquired in a business combination. The inter-relationship of these estimates makes it impractical to provide additional
quantitative analyses of the effects of changes in these estimates.

Valuation of Goodwill

Goodwill is tested for impairment at least annually. This requires us to estimate the fair values of our 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.
Generally, the higher the fair value assigned to both the oil and gas properties and non-oil and gas properties, the lower goodwill
would be. A lower goodwill value decreases the likelihood of an impairment charge. However, unfavorable changes in reserves or in our price
forecast, would increase the likelihood of a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or
capital resources. However, it would adversely affect Devon’s results of operations in that period.

Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide
quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in Devon’s reserve
estimates previously set forth.

44 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED

In December 2004, the Financial Accounting Standards Board (‘’FASB’’) issued SFAS No. 123(R), ‘’Share-Based Payment,’’ which is a
revision of SFAS No. 123 and supersedes APB Opinion No. 25 regarding stock-based employee compensation plans. APB Opinion No. 25
requires recognition of compensation expense only if the current market price of the underlying stock exceeded the stock option exercise
price on the date of grant. Additionally, SFAS No. 123 established fair value-based accounting for stock-based employee compensation plans
but allowed pro forma disclosure as an alternative to ﬁnancial statement recognition. SFAS No. 123(R) requires all share-based payments to
employees, including grants of employee stock options, to be valued at fair value on the date of grant, and to be expensed over the applicable
vesting period. Also, pro forma disclosure of the income statement effects of share-based payments is no longer an alternative. We will adopt
the provisions of SFAS No. 123(R) in the third quarter of 2005 and anticipate adopting SFAS No. 123(R) using the modiﬁed prospective
method. Under this method, Devon will recognize compensation expense for all stock-based awards granted or modiﬁed on or after July 1,
2005, as well as any previously granted awards that are not fully vested as of July 1, 2005. Compensation expense will be measured based on
the fair value of the awards previously calculated in developing the pro forma disclosures in accordance with the provisions of SFAS No. 123.
We are currently assessing the impact of adopting SFAS No. 123(R) on our consolidated results of operations. However, we do not expect
such impact to be material upon adoption in the third quarter of 2005.

In December 2004, the FASB issued Staff Position No. 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings
Repatriation Provision within the American Jobs Creation Act of 2004” (“FSP No. 109-2”). The American Jobs Creation Act of 2004 (the
“Act”), signed into law on October 22, 2004, provides for a special one-time tax deduction, or dividend received deduction (“DRD”), of
85% of qualifying foreign earnings that are repatriated in either a company’s last tax year that began before the enactment date or the ﬁrst tax
year that begins during the one-year period beginning on the enactment date. FSP 109-2 provides entities additional time to assess the effect
of repatriating foreign earnings under the Act for purposes of applying SFAS No. 109, “Accounting for Income Taxes,” which typically
requires the effect of a new tax law to be recorded in the period of enactment. In the ﬁrst quarter of 2005, Devon’s board of directors
approved the repatriation of $500 million of earnings from Canadian operations which will be taxed at a reduced income tax rate caused by
the DRD. As a result, Devon will recognize additional current income tax expense of approximately $30 million in the ﬁrst quarter of 2005.

SEC INQUIRY RELATING TO EQUATORIAL GUINEA

On August 6, 2004, the SEC notiﬁed Devon that it was conducting an inquiry into payments made to the government of Equatorial
Guinea, or to officials and persons affiliated with officials of the government of Equatorial Guinea. This inquiry follows an investigation and
public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the transactions of
various foreign governments, including that of Equatorial Guinea, with Riggs Bank. The investigation and hearing also reviewed the
operations of those U.S. oil companies having interests in Equatorial Guinea, including Devon. Devon is cooperating with the SEC inquiry.

2005 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, 2004 reserve reports and other data in our 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 our foreign operations are subject to currency exchange rate risks. Additional risks are discussed below in

the context of line items most affected by such risks.

Speciﬁc Assumptions and Risks Related to Price and Production Estimates

Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these products
are inﬂuenced by regional and worldwide economic conditions, weather and other local market conditions. These factors are beyond our
control and are difficult to predict. In addition to volatility in general, Devon’s oil, gas and NGL prices may vary considerably due to
differences between regional markets, differing quality of oil produced (i.e., sweet crude versus heavy or sour crude), differing Btu

D I S C O V E R I N G D E V O N 45

contents of gas produced, 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, our 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 will

continue at levels that allow for proﬁtable production of these products. There can be no assurance of such stability. Most of our Canadian
production is subject to government royalties that ﬂuctuate with prices. Thus, price ﬂuctuations can affect reported production. Also, our
international production is governed by payout agreements with the governments of the countries in which we operate. 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 our future processing and transport of oil, natural gas and NGLs are based on the assumption that market demand and
prices 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 from many causes. These causes include transportation and processing availability, mechanical failure, human error,
meteorological events including, but not limited to, hurricanes, and numerous other factors. The following forward-looking statements were
prepared assuming demand, curtailment, producibility and general market conditions for Devon’s oil, natural gas and NGLs during 2005
will be substantially similar to those of 2004, 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 2005 exchange rate of $0.82 U.S. to $1.00 Canadian. The actual 2005 exchange
rate may vary materially from this estimate. Such variations could have a material effect on the following estimates.

Though we have completed several major property acquisitions and dispositions in recent years, these transactions are opportunity
driven. Thus, the following forward-looking data excludes the ﬁnancial and operating effects of potential property acquisitions or divestitures,
except as discussed in “Property Acquisitions and Divestitures,” during the year 2005. The timing and ultimate results of such acquisition
and divestiture activity is difficult to predict, and may vary materially from that discussed in this report.

Geographic Reporting Areas for 2005

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.

Year 2005 Potential Operating Items

The estimates related to oil, gas and NGL production, operating costs and DD&A set forth in the following paragraphs are based

on estimates for Devon’s properties other than those that have been designated for possible sale (See “Property Acquisitions and
Divestitures”). Therefore, the following estimates exclude the results of the potential sale properties for the entire year.

Oil, Gas and NGL Production Set forth in the following paragraphs are individual estimates of Devon’s oil, gas and NGL
production for 2005. On a combined basis, Devon estimates its 2005 oil, gas and NGL production will total 217 MMBoe. Of this total,
approximately 92% is estimated to be produced from reserves classiﬁed as “proved” at December 31, 2004.

Oil Production We expect our oil production in 2005 to total 60 MMBbls. Of this total, approximately 95% is estimated to be

produced from reserves classiﬁed as “proved” at December 31, 2004. The expected production by area is as follows:

United States Onshore
United States Offshore
Canada
International

(MMBBLS)

12
10
12
26

Oil Prices – Fixed Through various price swaps, Devon has ﬁxed the price it will receive in 2005 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.

46 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

BBLS/DAY

PRICE/BBL

MONTHS
OF PRODUCTION

United States Offshore
Canada
International

10,000
6,000
6,000

$ 27.17
$ 27.26
$ 25.88

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
AS A % OF NYMEX PRICE

90% to 95%
91% to 96%
76% to 81%
84% to 90%

We have also entered into costless price collars that set a ﬂoor and ceiling price for a portion of our 2005 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. As long as Devon meets the ongoing requirements of hedge accounting for its derivatives, any such settlements will either increase
or decrease Devon’s oil revenues for the period. Because our oil volumes are often sold at prices that differ from the NYMEX or Brent price
due to differing quality (i.e., sweet crude versus heavy or 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.
The international oil prices shown in the following table have been adjusted to a NYMEX-based price, using our estimates of 2005

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

To simplify the presentation, Devon’s costless collars as of December 31, 2004, have been aggregated in the following table according

to similar ﬂoor prices and similar ceiling prices. The ﬂoor and ceiling prices shown are weighted averages of the various collars in each
aggregated group.

AREA

United States Onshore
United States Offshore
Canada
International

WEIGHTED AVERAGE

BBLS/DAY

3,000
17,000
15,000
15,000

FLOOR
PRICE
PER BBL

$
$
$
$

22.00
22.00
22.00
23.50

CEILING
PRICE
PER BBL

$ 28.25
$ 27.62
$ 28.28
$ 29.61

MONTHS OF
PRODUCTION

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

Gas Production We expect our 2005 gas production to total 804 Bcf. Of this total, approximately 90% is estimated to be produced

from reserves classiﬁed as “proved” at December 31, 2004. The expected production by area is as follows:

United States Onshore
United States Offshore
Canada
International

(BCF)

460
82
255
7

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

2005 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.

D I S C O V E R I N G D E V O N 47

United States Onshore
Canada
Canada
International

MCF/DAY

PRICE/MCF

7,343
38,578
38,578
12,000

$
$
$
$

3.40
2.89
2.96
2.35

MONTHS OF
PRODUCTION

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

Gas Prices – Floating For the natural gas production for which prices have not been ﬁxed, Devon’s 2005 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.

United States Onshore
United States Offshore
Canada
International

EXPECTED RANGE OF GAS PRICES
LESS THAN NYMEX PRICE

84% to 93%
98% to 107%
80% to 88%
50% to 60%

We have also entered into costless price collars that set a ﬂoor and ceiling price for a portion of our 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 our 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 our realized prices for
the production volumes related to the collars.

The prices shown in the following table have been adjusted to a NYMEX-based price, using our estimates of 2005 differentials

between NYMEX and the speciﬁc regional indices upon which the collars are based. The ﬂoor and ceiling prices related to the collars are
based on various regional ﬁrst-of-the-month price indices as published monthly by Inside FERC.

To simplify presentation, Devon’s costless collars have been aggregated in the following table according to similar ﬂoor prices and

similar ceiling prices. The ﬂoor and ceiling prices shown are weighted averages of the various collars in each aggregated group.

AREA

United States Onshore
United States Offshore
United States Offshore

MMBTU/DAY

40,000
40,000
70,000

WEIGHTED AVERAGE
FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

$
$
$

4.04
3.50
4.09

$
$
$

7.00
7.50
7.00

MONTHS OF
PRODUCTION

Jan – Jun
Jan – Dec
Jan – Jun

NGL Production Devon expects its 2005 production of NGLs to total 23 MMBbls. Of this total, 93% is estimated to be produced

from reserves classiﬁed as “proved” at December 31, 2004. The expected production by area is as follows:

United States Onshore
United States Offshore
Canada

(MMBBLS)

17
1
5

Marketing and Midstream Revenues and Expenses Devon’s marketing and midstream revenues and expenses are derived
primarily from its natural gas processing plants and natural gas transport pipelines. These revenues and expenses vary in response to several
factors. The factors include, but are not limited to, changes in production from wells connected to the pipelines and related processing
plants, changes in the absolute and relative prices of natural gas and NGL contract provisions, and the amount of repair and workover
activity required to maintain anticipated transportation and 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 2005 marketing and midstream revenues will
be between $1.26 billion and $1.40 billion, and marketing and midstream expenses will be between $1.00 billion and $1.10 billion.

48 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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 2005 lease operating expenses (including transportation costs) will be between $1.155
billion and $1.225 billion and production taxes will be between 3.25% and 3.75% of consolidated oil, natural gas and NGL revenues. This
excludes the effect on revenues from hedges, upon which production taxes are not incurred.

Depreciation, Depletion and Amortization (“DD&A”) The 2005 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 2005 compared
to the costs incurred for such efforts, and the revisions to Devon’s year-end 2004 reserve estimates that, based on prior experience, are likely
to be made during 2005.

Given these uncertainties, oil and gas property related DD&A expense for 2005 is expected to be between $1.86 billion and $1.94
billion. Based on these DD&A amounts and the production estimates set forth earlier, we expect our oil and gas property related DD&A
rate will be between $8.60 per Boe and $9.00 per Boe.

Additionally, we expect depreciation and amortization expense related to non-oil and gas property ﬁxed assets to total between $150

million and $160 million.

Accretion of Asset Retirement Obligation Devon expects its 2005 accretion of its asset retirement obligation to be between $40

million and $45 million.

General and Administrative Expenses (“G&A”) G&A includes the costs of many different goods and services used in support of
our 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.

The planned property dispositions have further added to the uncertainties around G&A estimates. Devon is currently in the process of

determining the appropriate staffing needs subsequent to the dispositions. Speciﬁcally excluded from these estimates are both severance
related costs and the cost savings that would result from an expected reduction of headcount. Any cost savings from these reductions will be
dependent not only on the level of staff reductions, but also on the timing. As a result, until this process is complete, actual 2005 G&A
could vary materially from current estimates.

Given these limitations, consolidated G&A in 2005 is expected to be between $260 million and $280 million.

Reduction of Carrying Value of Oil and Gas Properties We follow the full cost method of accounting for our oil and gas
properties. Under the full cost method, Devon’s net book value of oil and gas properties, less related deferred income taxes (the “costs to be
recovered”), may not exceed a calculated “full cost ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues
from oil and gas properties plus the cost of properties not subject to amortization. The ceiling is imposed separately by country. In
calculating future net revenues, current prices and costs used are those as of the end of the appropriate quarterly period. These prices are not
changed except where different prices are ﬁxed and determinable from applicable contracts for the remaining term of those contracts. Such
contracts include derivatives accounted for as cash ﬂow hedges. 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 our long-term
price forecast that is a barometer for true fair value. Therefore, oil and gas property writedowns that result from applying the full cost ceiling
limitation, and that are caused by ﬂuctuations in price as opposed to reductions to the underlying quantities of reserves, should not be
viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

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

future periods.

D I S C O V E R I N G D E V O N 49

Interest Expense Future interest rates and debt outstanding have a signiﬁcant effect on Devon’s interest expense. Additionally, we
can only marginally inﬂuence the prices we will receive in 2005 from sales of oil, natural gas and NGLs and the resulting cash ﬂow. These
factors increase the margin of error inherent in estimating future interest expense. Other factors which affect interest expense, such as the
amount and timing of capital expenditures, are within our control.

The interest expense in 2005 related to our ﬁxed-rate debt, including net accretion of related discounts, will be approximately $430

million. This ﬁxed-rate debt removes the uncertainty of future interest rates from some, but not all, of Devon’s long-term debt. Our ﬂoating
rate debt is discussed in the following paragraphs.

We have various debt instruments which have been converted to ﬂoating rate debt through the use of interest rate swaps. Our ﬂoating

rate debt is as follows:

DEBT INSTRUMENT

7.625% senior notes due in 2005
10.25% bonds due in 2005
2.75% notes due in 2006
6.55% senior notes due 2006
4.375% senior notes due in 2007
6.75% senior notes due 2011

NOTIONAL AMOUNT
(IN MILLIONS)

FLOATING RATE

$ 125
$ 235
$ 500
$ 166 (1)
$ 400
$ 400

LIBOR plus 237 basis points
LIBOR plus 711 basis points
LIBOR less 26.8 basis points
Banker’s Acceptance plus 340 basis points
LIBOR plus 40 basis points
LIBOR plus 197 basis points

(1) Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8308 as of December 31, 2004.

Based on future LIBOR rates as of January 31, 2005, interest expense on our ﬂoating rate debt, including net amortization of

premiums, is expected to total between $75 million and $85 million in 2005.

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 $5 million and $15 million of such items to be included in our 2005 interest expense. Also, we expect to capitalize between
$65 million and $75 million of interest during 2005.

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, other than the retirement of debt due to mature in 2005, we expect our 2005 interest expense will
be between $445 million and $455 million.

Effects of Changes in Foreign Currency Rates Our Canadian subsidiary has $400 million of ﬁxed-rate senior notes which are
denominated in U.S. dollars. Changes in the exchange rate between the U.S. dollar and the Canadian dollar during 2005 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 2005. However, based on the December 31, 2004, Canadian-to-U.S. dollar
exchange rate of $0.8308 and Devon’s forecast 2005 rate of $0.8200, we expect to record an expense of approximately $5 million. The actual
2005 effect will depend on the exchange rate as of December 31, 2005.

Other Revenues Devon’s other revenues in 2005 are expected to be between $260 million and $270 million. Included as part of

other revenues is a $150 million gain on the sale of certain assets in the ﬁrst quarter of 2005.

Our estimate of 2005 other revenues does not include the effect of any early settlements or hedge ineffectiveness of outstanding

commodity price hedges as a result of the property dispositions. The amount of any settlement gain or loss or hedge ineffectiveness will
depend not only on the timing of the property sales but also on the forward prices in effect at that time. As a result, Devon is unable to
predict the effect that these early settlements or hedge ineffectiveness may have on its earnings. Under current market conditions, we would
expect to record a loss on these early settlements or hedge ineffectiveness.

Income Taxes Our ﬁnancial income tax rate in 2005 will vary materially depending on the actual amount of ﬁnancial pre-tax
earnings. The tax rate for 2005 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 2005’s income tax expense regardless of the level of pre-tax earnings that are produced. Given the uncertainty of our
pre-tax earnings amount, we estimate that our consolidated ﬁnancial income tax rate in 2005 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 2005’s
ﬁnancial income tax rates.

50 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Property Acquisitions and Divestitures 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.

During 2005, we contemplate the disposition of certain oil and gas properties (the “Disposition Properties”). The Disposition

Properties are predominantly properties that are either outside of our core operating areas or otherwise do not ﬁt our current strategic
objectives. The Disposition Properties are located in the U.S. and Canada. At this time, we expect the dispositions will occur in the ﬁrst
half of 2005.

The estimates of our 2005 results previously set forth exclude any results from the Disposition Properties. The Disposition Properties’
actual contributions to our 2005 operating results will depend upon the timing of the dispositions. The estimated ﬁrst quarter 2005 results
from the Disposition Properties (which are not included in the previous 2005 estimates in this report) are as follows:

United States Onshore
United States Offshore
Canada
Total

ESTIMATED PRODUCTION – 1ST QUARTER 2005

OIL
(MMBBLS)

GAS
(BCF)

NGLs
(MMBBLS)

TOTAL
(MMBOE)

0.4
1.7
0.5
2.6

6
11
9
26

0.3
0.1
—
0.4

1.7
3.6
2.0
7.3

EXPECTED RANGE OF EXPENSE – 1ST QUARTER 2005
(IN MILLIONS)

Lease operating expenses, including transportation
DD&A expenses

$48 to $50
$76 to $78

Not included in these estimates is the effect of any early settlements or hedge ineffectiveness of outstanding commodity price hedges as

a result of the dispositions. The amount of any settlement gain or loss or hedge ineffectiveness will depend not only on the timing of the
property sales but also on the forward prices in effect at that time. As a result, Devon is unable to predict the effect that these early
settlements or hedge ineffectiveness may have on its earnings. Under current market conditions, we would expect to record a loss on these
early settlements.

Year 2005 Potential Capital Sources, Uses and Liquidity

Capital Expenditures Devon’s capital expenditures budget is based on an expected range of future oil, natural gas and NGL prices as
well as the expected costs of the capital additions. Should actual prices received differ materially from Devon’s price expectations for its future
production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2005 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 our estimates.

Given the limitations discussed, we expect 2005 capital expenditures for drilling and development efforts, plus related facilities, to total
between $2.6 billion and $3.0 billion. These amounts include between $390 million and $450 million for drilling and facilities costs related
to reserves classiﬁed as proved as of year-end 2004. In addition, these amounts include between $1.345 billion and $1.555 billion for other
production capital and between $865 million and $995 million for exploration capital. Other production capital includes 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. Exploration capital includes exploratory drilling to ﬁnd and produce oil or gas in previously untested fault blocks or
new reservoirs.

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

Production capital related to

proved reserves

Other production capital
Exploration capital
Total

EXPLORATION AND PRODUCTION EXPENDITURES

UNITED STATES
ONSHORE

UNITED STATES
OFFSHORE

$ 190 - $ 215
$ 655 - $ 765
$ 165 - $ 190
$1,010 - $1,170

$ 85 - $ 95
$ 40 - $ 50
$240 - $265
$365 - $410

CANADA
(IN MILLIONS)

$ 70 -$ 85
$615 - $ 695
$310 - $ 345
$995 - $1,125

INTERNATIONAL

TOTAL

$ 45 - $ 55
$ 35 - $ 45
$150 - $195
$230 - $295

$ 390 -$ 450
$1,345 -$1,555
$ 865 - $ 995
$2,600 - $3,000

D I S C O V E R I N G D E V O N 51

In addition to the above expenditures for drilling and development, Devon expects to spend between $85 million to $95 million on its

marketing and midstream assets, which include its oil pipelines, gas processing plants, CO2 removal facilities and gas transport pipelines.
We also expect to capitalize between $165 million and $175 million of G&A expenses in accordance with the full cost method of
accounting and to capitalize between $65 million and $75 million of interest. We also expect to pay between $25 million and $30 million
for plugging and abandonment charges, and to spend between $70 million and $80 million for other non-oil and gas property ﬁxed assets.

Other Cash Uses Devon’s management expects the policy of paying a quarterly common stock dividend to continue. With the
current $0.075 per share quarterly dividend rate and 484 million shares of common stock outstanding as of December 31, 2004, dividends
are expected to approximate $145 million. Also, Devon has $150 million of 6.49% cumulative preferred stock upon which it will pay $10
million of dividends in 2005.

On September 27, 2004, Devon announced its intention to buy back up to 50 million shares of its common stock in conjunction

with a stock buyback program. The shares will be repurchased with cash ﬂow from operations and proceeds from the planned property
divestitures. As of February 28, 2005, Devon has repurchased 12.5 million shares at a total cost of $501 million, or $40.04 per share.

Capital Resources and Liquidity Devon’s estimated 2005 cash uses, including its drilling and development activities and repurchase
of common stock, are expected to be funded primarily through a combination of working capital, operating cash ﬂow and proceeds from its
planned property divestitures, with the remainder, if any, funded with borrowings from our credit facility. The amount of operating cash ﬂow
to be generated during 2005 is uncertain due to the factors affecting revenues and expenses as previously cited. However, we expect our
combined capital resources to be more than adequate to fund our anticipated capital expenditures and other cash uses for 2005. As of
December 31, 2004, we had $2.1 billion of cash and short-term investments and $1.3 billion available under our $1.5 billion of credit
facilities, net of $0.2 billion of outstanding letters of credit. If signiﬁcant acquisitions or other unplanned capital requirements arise during
the year, we could utilize our 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 our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, gas and NGL production. Realized pricing is primarily driven

by the prevailing worldwide price for crude oil and spot market prices applicable to our 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 we
will receive a ﬁxed price for our 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’s total hedged positions on future production as of December 31, 2004 are set forth in the following tables.

Price Swaps Through various price swaps, we have ﬁxed the price we will receive on a portion of our oil and natural gas production

in 2005. The following tables include information on this ﬁxed-price production by area. Where necessary, the oil and gas prices related to
these swaps have been adjusted for certain transportation costs that are netted against the price recorded by Devon, and the gas price has also
been adjusted for the Btu content of the production that has been hedged.

52 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

OIL PRODUCTION

AREA

United States Onshore
Canada
International

GAS PRODUCTION

AREA

United States Onshore

BBLS/DAY

PRICE/BBL

10,000
6,000
6,000

$ 27.17
$ 27.26
$ 25.88

MCF/DAY

PRICE/MCF

MONTHS OF
PRODUCTION

Jan – Dec
Jan – Dec
Jan – Dec

MONTHS OF
PRODUCTION

7,343

3.40

Jan – Dec

Costless Price Collars We have also entered into costless price collars that set a ﬂoor and ceiling price for a portion of our 2005 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. As long as Devon meets the ongoing requirements of hedge accounting for its derivatives, any such
settlements will either increase or decrease Devon’s oil revenues for the period. Because our oil volumes are often sold at prices that differ
from the NYMEX or Brent price due to differing quality (i.e., sweet crude versus heavy or 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 also entered into costless price collars that set a ﬂoor and ceiling price for a portion of our 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, our costless collars as of December 31, 2004 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 table have been adjusted to a NYMEX-based price, using our estimates of 2005

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 our 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.

OIL PRODUCTION

AREA

United States Onshore
United States Offshore
Canada
International

GAS PRODUCTION

AREA

United States Onshore
United States Offshore
United States Offshore

2005
WEIGHTED AVERAGE

FLOOR
PRICE PER
BBL

CEILING
PRICE PER
BBL

$ 22.00
$ 22.00
$ 22.00
$ 23.50

$ 28.25
$ 27.62
$ 28.28
$ 29.61

2005
WEIGHTED AVERAGE

FLOOR
PRICE PER
MMBTU

CEILING
PRICE PER
MMBTU

$
$
$

4.04
3.50
4.09

$
$
$

7.00
7.50
7.00

BBLS/DAY

3,000
17,000
15,000
15,000

MMBTU/DAY

40,000
40,000
70,000

MONTHS OF
PRODUCTION

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

MONTHS OF
PRODUCTION

Jan – Jun
Jan – Dec
Jan – Jun

D I S C O V E R I N G D E V O N 53

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, 2004, a 10% increase in the underlying commodities’ prices
would have increased the net liabilities recorded for our commodity hedging instruments by $115 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.

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

We also have ﬁxed-price physical delivery contracts for the years 2005 through 2008 covering International natural gas production of 4

Bcf per year, except in 2008 when the volume drops to 3 Bcf.

Interest Rate Risk

At December 31, 2004, Devon had debt outstanding of $8.0 billion. Of this amount, $6.0 billion, or 75%, bears interest at ﬁxed rates

averaging 7.0%. Devon also has a ﬂoating-to-ﬁxed interest rate swap in which we will record a ﬁxed rate of 6.4% on a notional amount of
$104 million in 2005 and 2006 and 6.3% on a notional amount of $32 million in 2007.

The remaining $1.8 billion of debt outstanding bears interest at ﬂoating rates. Included in the ﬂoating-rate debt is ﬁxed-rate debt
which has been converted to ﬂoating-rate debt through interest rate swaps. The terms of Devon’s Senior Credit Facility allow interest rates to
be ﬁxed at our option for periods of between seven to 180 days. As of December 31, 2004, there were no borrowings outstanding under the
Senior Credit Facility. Following is a table summarizing the ﬁxed-to-ﬂoating interest rate swaps with the related debt instrument and
notional amounts.

DEBT INSTRUMENT

7.625% senior notes due in 2005
10.25% bonds due in 2005
2.75% notes due in 2006
6.55% senior notes due 2006
4.375% senior notes due in 2007
6.75% senior notes due 2011

NOTIONAL AMOUNT
(IN MILLIONS)

FLOATING RATE

$
$
$
$
$
$

125
235
500
166 (1)
400
400

LIBOR plus 237 basis points
LIBOR plus 711 basis points
LIBOR less 26.8 basis points
Banker’s Acceptance plus 340 basis points
LIBOR plus 40 basis points
LIBOR plus 197 basis points

(1) Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8308 as of December 31, 2004.

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, 2004, a 10% increase in the underlying interest rates would have decreased the fair
value of Devon’s interest rate swaps by $28 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.

Our 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 us to record a charge of approximately $40 million in 2005. 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.

54 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Report of Independent Registered Public Accounting Firm

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,

2004 and 2003, 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, 2004. 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 the standards of the Public Company Accounting Oversight Board (United States). Those

standards require that we plan and perform the audit to obtain reasonable assurance about whether the ﬁnancial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the ﬁnancial
statements. An audit also includes assessing the accounting principles used and signiﬁcant estimates made by management, as well as
evaluating the overall ﬁnancial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated ﬁnancial statements referred to above present fairly, in all material respects, the ﬁnancial position of
Devon Energy Corporation and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash ﬂows for
each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

As described in Note 1 to the consolidated ﬁnancial statements, as of January 1, 2003, the Company adopted Statement of Financial

Accounting Standards No. 143, Asset Retirement Obligations.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the

effectiveness of Devon Energy Corporation’s internal control over ﬁnancial reporting as of December 31, 2004, based on criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated March 4, 2005 expressed an unqualiﬁed opinion on management’s assessment of, and the
effective operation of, internal control over ﬁnancial reporting.

Oklahoma City, Oklahoma
March 4, 2005

D I S C O V E R I N G D E V O N 55

Consolidated Balance Sheets

DEVON ENERGY CORPORATION AND SUBSIDIARIES

DECEMBER 31, (IN MILLIONS, EXCEPT SHARE DATA)

2004

2003

ASSETS:
Current assets:

Cash and cash equivalents
Short-term investments
Accounts receivable
Fair value of derivative ﬁnancial instruments
Other current assets

Total current assets

Property and equipment, at cost, based on the full cost method of accounting for

oil and gas properties ($3,187 and $3,336 excluded from amortization in
2004 and 2003, respectively)
Less accumulated depreciation, depletion and amortization

Investment in ChevronTexaco Corporation common stock, at fair value
Fair value of derivative 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
Accrued interest payable
Fair value of derivative ﬁnancial instruments
Current portion of asset retirement obligation
Accrued expenses and other current liabilities

Total current liabilities
Debentures exchangeable into shares of

ChevronTexaco Corporation common stock

Other long-term debt
Preferred stock of a subsidiary
Fair value of derivative ﬁnancial instruments
Asset retirement obligation, long-term
Other liabilities
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 483,909,000 in 2004 and 479,534,000 in 2003

Additional paid-in capital
Retained earnings
Accumulated other comprehensive income
Deferred compensation and other
Treasury stock, at cost: none in 2004 and 7,354,000 shares in 2003

Total stockholders’ equity

Commitments and contingencies (Note 14)

Total liabilities and stockholders’ equity

See accompanying notes to consolidated ﬁnancial statements

56 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

1,152
967
1,320
1
143
3,583

32,114
12,768
19,346
745
8
5,637
417
29,736

715
487
223
933
139
399
46
158
3,100

692
6,339
—
72
693
366
4,800

48
9,087
3,693
930
(85)
—
13,674

29,736

932
341
946
13
132
2,364

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

859
315
15
338
130
153
42
219
2,071

677
7,903
55
52
629
349
4,370

47
9,043
1,614
569
(32)
(186)
11,056

27,162

Consolidated Statements of Operations

DEVON ENERGY CORPORATION AND SUBSIDIARIES
DEVON ENERGY CORPORATION AND SUBSIDIARIES

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

2004

2003

2002

REVENUES:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues

OPERATING COSTS AND EXPENSES:

Lease operating expenses
Production taxes
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization of oil and gas properties
Depreciation and amortization of non-oil and gas properties
Accretion of asset retirement obligation
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 derivative 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 stockholders

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

2,202
4,732
554
1,701
9,189

1,280
255
1,339
2,141
149
44
277
—
—
5,485
3,704

(475)
—
23
(62)
—
103
(411)

3,293

752
355
1,107

2,186

—
—
—
2,186
—
2,186
10
2,176

4.51
—
—
4.51

4.38
—
—
4.38

482
499

1,588
3,897
407
1,460
7,352

1,078
204
1,174
1,668
125
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

4.12
—
0.04
4.16

4.00
—
0.04
4.04

417
433

909
2,133
275
999
4,316

775
111
808
1,106
105
—
219
—
651
3,775
541

(533)
—
1
28
(205)
34
(675)

(134)

23
(216)
(193)

54
9
45
104
—
104
10
94

0.16
0.15
—
0.31

0.16
0.14
—
0.30

309
313

D I S C O V E R I N G D E V O N 57

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Loss)

DEVON ENERGY CORPORATION AND SUBSIDIARIES

PREFERRED COMMON
STOCK

STOCK

ADDITIONAL
PAID-IN
CAPITAL

ACCUMULATED
OTHER
COMPRE-
HENSIVE
(ACCUMULATED INCOME
(LOSS)

RETAINED
EARNINGS

DEFICIT)

DEFERRED
COMPEN-
SATION
AND OTHER

—

—
—
—
—

—
—
—
—
—
1

—

—
—
—

—
—
—
—
—
—
—
1

—

—
—
—

—
—
—
—
—
—
—
—
—
—
1

—

—
—
—
—

6
—
—
—
—
31

—

—
—
—

14
—
—
—
2
—
—
47

—

—
—
—

1
—
—
—
—
—
—
—
—
—
48

3,598

(147)

(28)

—

—
—
—
—

1,556
6
—
—
3
5,163

—

—
—
—

3,817
31
—
—
32
—
—
9,043

—

—
—
—

264
(189)
—
54
—
—
66
—
(151)
—
9,087

104

—

—
—
—
—

—
—
(31)
(10)
—
(84)

1,747

—

—
—
—

—
—
(39)
(10)
—
—
—
1,614

2,186

—

—
—
—

—
—
—
—
(97)
(10)
—
—
—
—
3,693

—

(39)

(217)
(54)
(103)
128

—
—
—
—
—
(267)

—

766

198

(236)
19
89

—
—
—
—
—
—
—
569

—

388

410

(561)
39
85

—
—
—
—
—
—
—
—
—
—
930

—

—
—
—
—

—
—
—
—
(3)
(3)

—

—
—
—

—
—
—
—
(34)
2
3
(32)

—

—
—
—

—
—
—
—
—
—
(66)
11
—
2
(85)

TOTAL
STOCK-

TREASURY HOLDERS’

STOCK

EQUITY

(190)

3,259

—

—
—
—
—

2
—
—
—
—
(188)

—

—
—
—

2
—
—
—
—
—
—
(186)

—

104

(39)

(217)
(54)
(103)
128
(239)
(135)
1,564
6
(31)
(10)
—
4,653

1,747

766

198

(236)
19
89
836
2,583
3,833
31
(39)
(10)
—
2
3
11,056

2,186

388

410

—
—
—

(561)
39
85
361
2,547
244
(21)
(189)
—
56
56
54
—
(97)
—
(10)
—
—
—
11
—
—
151
—
2
— 13,674

(IN MILLIONS)

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 derivative 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 derivative 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
Comprehensive income:

instruments

Minimum pension liability adjustment
Unrealized gain on marketable securities

Other comprehensive income

Comprehensive income

Stock issued
Stock repurchased and retired
Conversion of preferred stock of a subsidiary
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
Retirement of treasury stock
Other
BALANCE AS OF DECEMBER 31, 2004

See accompanying notes to consolidated ﬁnancial statements

58 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Consolidated Statements of Cash Flows

DEVON ENERGY CORPORATION AND SUBSIDIARIES
DEVON ENERGY CORPORATION AND SUBSIDIARIES

YEAR ENDED DECEMBER 31, (IN MILLIONS)

2004

2003

2002

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
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 derivative ﬁnancial instruments
Reduction of carrying value of oil and gas properties
Impairment of ChevronTexaco Corporation common stock
Operating cash ﬂows from discontinued operations
(Gain) loss 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
Other current assets
Long-term other assets

Increase (decrease) in:
Accounts payable
Income taxes payable
Accrued interest and expenses
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
Purchases of short-term investments
Sales of short-term investments
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 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

2,186

1,731

2,290
44
11
(23)
62
—
—
—
(34)
355
31

(345)
(20)
(91)

190
208
(79)
31
4,816

95
(3,103)
(3,215)
2,589

—
—
(3,634)

—
(973)
268
(189)
(97)
(10)
—
(1,001)
39
220
932
1,152

1,793
36
19
(69)
(1)
111
—
—
7
321
(48)

(164)
(34)
—

42
62
(2)
(36)
3,768

179
(2,587)
(702)
361

—
(24)
(2,773)

597
(1,118)
155
—
(39)
(10)
1
(414)
59
640
292
932

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

(80)
22
—

(74)
21
(10)
(56)
1,754

1,067
(3,426)
—
—

316
(3)
(2,046)

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

D I S C O V E R I N G D E V O N 59

DECEMBER 31, 2004, 2003 AND 2002

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Notes To Consolidated
Financial Statements
1

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.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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
constructing and operating 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 estimates of proved reserves and related present value
estimates of future net revenue, the carrying value of oil and gas properties, goodwill impairment assessment, asset retirement obligations,
income taxes, valuation of derivative instruments, obligations related to employee beneﬁts and legal and environmental risks and exposures.
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
NGL reserves plus the cost of properties not subject to amortization. Estimated future net revenues exclude future cash outﬂows associated
with settling asset retirement obligations included in the net book value of oil and gas properties. 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 obligations, 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

60 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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 of midstream pipelines are provided on a units-of-production basis. Depreciation and amortization of other property and

equipment, including corporate and other midstream assets and leasehold improvements, are provided using the straight-line method based
on estimated useful lives from three to 39 years.

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.

Assuming the provisions of SFAS No. 143 had been adopted as of January 1, 2002, Devon’s 2002 net earnings would have been
$5 million less than the reported 2002 net earnings. This would have also resulted in a $0.02 and $0.01 reduction to 2002 basic and diluted
net earnings applicable to common stockholders, respectively.

In September 2004, the SEC issued Staff Accounting Bulletin No. 106 (“SAB No. 106”) to provide guidance regarding the interaction
of SFAS No. 143 with the full cost method of accounting for oil and gas properties. Speciﬁcally, SAB No. 106 clariﬁes the manner in which
the full cost ceiling test and depletion of oil and gas properties should be calculated in accordance with the provisions of SFAS No. 143.
Devon adopted SAB No. 106 prospectively in the fourth quarter of 2004. However, this adoption did not materially impact the full cost
ceiling test calculation or depletion for 2004.

Short-Term Investments and Other Marketable Securities

Devon reports its short-term investments and other marketable securities at fair value, except for debt securities in which management

has the ability and intent to hold until maturity. At December 31, 2004 and 2003, Devon’s short-term investments consisted of $967
million and $341 million, respectively, of auction rate securities classiﬁed as available for sale. Although Devon’s auction rate securities have
contractual maturities of more than 10 years, the underlying interest rates on such securities reset at intervals ranging from 7 to 49 days.
Therefore, these auction rate securities are priced and subsequently trade as short-term investments because of the interest rate reset feature.
As a result, Devon has classiﬁed its auction rate securities as short-term investments in the accompanying consolidated balance sheet. The
2003 balance of such securities was previously classiﬁed as cash equivalents due to the liquidity and pricing reset feature. In 2004, these
securities were reclassiﬁed as short-term investments to conform to current year presentation. There was no impact on net earnings or cash
ﬂow from operations as a result on the reclassiﬁcation.

Devon’s only other signiﬁcant investment security is its investment in approximately 14.2 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 and is tested

for impairment at least annually. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting
units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value
of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the
goodwill through a charge to expense. Because quoted market prices are not available for Devon’s reporting units, the fair values of the
reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums
paid. Devon performed annual impairment tests of goodwill in the fourth quarters of 2004, 2003 and 2002. Based on these assessments, no
impairment of goodwill was required.

The table below provides a summary of Devon’s goodwill, by assigned reporting unit, as of December 31, 2004 and 2003:

United States
Canada
International
Total

2004

3,061
2,508
68
5,637

DECEMBER 31,

(IN MILLIONS)

2003

3,073
2,336
68
5,477

D I S C O V E R I N G D E V O N 61

Notes To Consolidated Financial Statements

Revenue Recognition and Gas Balancing

Oil, gas and NGL revenues are recognized when production is sold to a purchaser at a ﬁxed or determinable price, when delivery has

occurred and title has transferred, and if collectibility of the revenue is probable. Delivery occurs and title is transferred when production has
been delivered to a pipeline or truck or a tanker lifting has occurred. Cash received relating to future production is deferred and recognized
when all revenue recognition criteria are met.

Devon follows the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to

which Devon is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only
when the estimated remaining reserves will not be sufficient to enable the underproduced owner to recoup its entitled share through
production. 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. The liability is priced based on current market prices. No receivables are recorded for those wells where Devon has
taken less than its share of production unless all revenue recognition criteria are met.

Marketing and midstream revenues are recorded at the time products are sold or services are provided to third parties at a ﬁxed or
determinable price, when delivery or performance has occurred and title has transferred, and if collectibility of the revenue is probable.
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. The gas purchased under these contracts is processed in Devon-owned plants.

Major Purchasers

No purchaser accounted for over 10% of revenues in 2004, 2003 and 2002.

Derivative Instruments

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.

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. 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 attributable to the effective portion of these hedging instruments are not
included in Devon’s consolidated results of operations. Instead, the changes in fair value of the effective portion of these hedging instruments,
net of tax, are recorded directly to accumulated other comprehensive income, a component of stockholders’ equity, until the hedged oil or
natural gas quantities are produced. The ineffective portion of these hedging instruments is included in consolidated results of operations.
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 or the hedged transaction is no longer likely to occur, the changes in fair value of these hedging
instruments would not be recorded directly to equity but in the consolidated results of operations. During 2004, 2003 and 2002, 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 enter into derivative
contracts only 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
accumulated other comprehensive income. These amounts are reclassiﬁed to oil and gas sales when the forecasted transaction takes place.

During 2004, 2003 and 2002, Devon recorded in its statements of operations a loss of $62 million, a gain of $1 million and a gain of
$28 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.

62 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

As of December 31, 2004, $395 million of net deferred losses on derivative instruments accumulated in accumulated other
comprehensive income are expected to be reclassiﬁed to oil and gas sales during the next 12 months assuming no change in the forward
commodity prices from the December 31, 2004 forward 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 natural 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 under its various derivative instruments is 12 months.

Common Stock

On September 27, 2004, Devon declared a two-for-one stock split, effected in the form of a stock dividend, to stockholders of record
on October 29, 2004. Common stock shares and per share amounts for prior years have been restated to reﬂect this two-for-one stock split.

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, (“SFAS No. 123”) 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 2004, 2003 and 2002 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 stockholders, 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 stockholders, pro forma

Net earnings per share available to common stockholders:

As reported:
Basic
Diluted
Pro forma:
Basic
Diluted

YEAR ENDED DECEMBER 31,

2002
2004
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

2003

2,176

(31)
2,152

4.51
4.38

4.46
4.33

$
$

1,737

(23)
1,716

4.16
4.04

4.11
3.99

(17)
78

0.31
0.30

0.25
0.25

The weighted average fair values of stock options granted during 2004, 2003 and 2002 were $10.32, $8.14 and $7.63, 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 2004, 2003 and 2002, respectively: risk-free interest rates of 3.2%, 2.8% and 3.2%; dividend
yields of 0.5%, 0.4% and 0.4%; expected lives of four, four and ﬁve years; and volatility of the price of the underlying common stock of
32.2%, 37.9% and 41.8%.

Income Taxes

Devon accounts for income taxes using the asset and liability method, whereby deferred tax assets and liabilities are recognized for
the future tax consequences attributable to differences between the ﬁnancial statement carrying amounts of assets and liabilities and their
respective tax bases, as well as the future tax consequences attributable to the future utilization of existing tax net operating loss and other
types of carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the
years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and
liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. For 2004, undistributed
earnings of foreign subsidiaries were determined to be permanently reinvested. Therefore, no U.S. deferred income taxes were provided
on such amounts at December 31, 2004.

D I S C O V E R I N G D E V O N 63

Notes To Consolidated Financial Statements

In October 2004, Congress enacted new tax legislation allowing qualifying corporations to repatriate cash from foreign operations at a

reduced income tax rate. In addition, this tax legislation creates a new U.S. tax deduction which will be phased in starting in 2005 for
companies with domestic production activities, including oil and gas extraction. In the ﬁrst quarter of 2005, Devon’s board of directors
approved the repatriation of $500 million of earnings from Canadian operations which will be taxed at the reduced income tax rate. As a
result, Devon will recognize, in the ﬁrst quarter of 2005, approximately $30 million of additional current income tax expense (which would
have been the same approximate amount recognized in 2004 if Devon had ﬁnalized its repatriation plans prior to 2005).

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 2004, 2003 and 2002.

YEAR ENDED DECEMBER 31, 2004:

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 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, 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

NET EARNINGS
APPLICABLE TO
COMMON
STOCKHOLDERS

WEIGHTED
AVERAGE
COMMON SHARES
OUTSTANDING
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

NET
EARNINGS
PER SHARE

2,176

—

10
2,186

1,737

—

9
1,748

—
94

482

9
499

417

9
433

309

4
313

4.51

4.38

4.16

4.04

0.31

0.30

The senior convertible debentures included in the 2004 and 2003 dilution calculations were not included in the 2002 dilution

calculation because the effect of inclusion was anti-dilutive.

64 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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.

2004

2003

2002

Options excluded from dilution calculation (in millions)
Range of exercise prices
Weighted average exercise price

4
$33.00 – $44.83
38.22
$

10
$24.96 – $44.83
28.05
$

11
$22.75 – $44.83
25.42
$

The excluded options for 2004 expire between January 9, 2007 and December 8, 2012.

Foreign Currency Translation Adjustments

Devon’s Canadian subsidiaries use the Canadian dollar as their functional currency. Therefore, the assets and liabilities of Devon’s

Canadian subsidiaries are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates, while income
and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included
in accumulated other comprehensive income in stockholders’ equity. Devon’s International subsidiaries use the U.S. dollar as their functional
currency.

Statements of Cash Flows

For purposes of the consolidated statements of cash ﬂows, Devon considers all highly liquid investments with original contractual

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.

Reclassiﬁcations

Certain prior period amounts have been reclassiﬁed to conform to the current year presentation.

Impact of Recently Issued Accounting Standards Not Yet Adopted

In December 2004, the Financial Accounting Standards Board (‘’FASB’’) issued SFAS No. 123(R), ‘’Share-Based Payment’’, (“SFAS

No. 123(R)”) which is a revision of SFAS No. 123 and supersedes APB Opinion No. 25 regarding stock-based employee compensation
plans. APB Opinion No. 25 requires recognition of compensation expense only if the current market price of the underlying stock exceeded
the stock option exercise price on the date of grant. Additionally, SFAS No. 123 established fair value-based accounting for stock-based
employee compensation plans but allowed pro forma disclosure as an alternative to ﬁnancial statement recognition. SFAS No. 123(R)
requires all share-based payments to employees, including grants of employee stock options, to be valued at fair value on the date of grant,
and to be expensed over the applicable vesting period. Also, pro forma disclosure of the income statement effects of share-based payments is
no longer an alternative. Devon will adopt the provisions of SFAS No. 123(R) in the third quarter of 2005 and anticipates adopting SFAS
No. 123(R) using the modiﬁed prospective method. Under this method, Devon will recognize compensation expense for all stock-based
awards granted or modiﬁed on or after July 1, 2005, as well as, any previously granted awards that are not fully vested as of July 1, 2005.
Compensation expense will be measured based on the fair value of the awards previously calculated in developing the pro forma disclosures
in accordance with the provisions of SFAS No. 123. Devon is currently assessing the impact of adopting SFAS No. 123(R) on consolidated
results of operations. However, Devon does not expect such impact to be material upon adoption in the third quarter of 2005.

D I S C O V E R I N G D E V O N 65

Notes To Consolidated Financial Statements

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 0.828 shares of
its common stock for each outstanding share of Ocean common stock (or a total of approximately 148 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 allocation to assets and liabilities are shown below.

(IN MILLIONS, EXCEPT SHARE PRICE)

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 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

148
24.03
3,546
114

64
124
3,848

650
1,436
97
121
89
954
7,195

256
4,262
1,060
85
39
1,493
7,195

$
$

Pro Forma Information

Set forth in the following table is certain unaudited pro forma ﬁnancial information for the year ended December 31, 2003. The

information has been prepared assuming the Ocean merger and Devon’s January 24, 2002 merger with Mitchell Energy & Development
Corp. 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.

66 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

REVENUES:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues

OPERATING COSTS AND EXPENSES:

Lease operating expenses
Production taxes
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization of oil and gas properties
Depreciation and amortization of non-oil and gas properties
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):

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) 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

PRO FORMA INFORMATION
YEAR ENDED DECEMBER 31,

2003

2002

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

1,840
4,155
416
1,461
7,872

1,167
219
1,174
1,859
125
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

1,025
148
873
1,740
122
—
321
727
4,956

621

(582)
(3)
1
28
(205)
32
(729)

(108)

47
(199)
(152)

54
9
45

89
—
89
10
79

D I S C O V E R I N G D E V O N 67

Notes To Consolidated Financial Statements

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)

3.95
—
0.06
4.01

3.83
—
0.06
3.89

463
481

72
913
23
247

0.08
0.10
—
0.18

0.07
0.10
—
0.17

458
472

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, 2004, 2003
and 2002, 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, 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

BALANCE AS OF DECEMBER 31, 2003

2004 activity
Deferred taxes
2004 activity, net of deferred taxes

(145)
46
—
46

(99)
894
(128)
766

667
426
(38)
388

BALANCE AS OF DECEMBER 31, 2004

1,055

159
(379)
123
(256)

(97)
(41)
3
(38)

(135)
(213)
62
(151)

(286)

(17)
(85)
31
(54)

(71)
28
(9)
19

(52)
61
(22)
39

(13)

(25)
41
(16)
25

—
141
(52)
89

89
132
(47)
85

174

TOTAL

(28)
(377)
138
(239)

(267)
1,022
(186)
836

569
406
(45)
361

930

The 2002 activity for unrealized gain (loss) on marketable securities includes 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.

68 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

SUPPLEMENTAL CASH FLOW INFORMATION

Cash payments (refunds) for interest and income taxes in 2004, 2003 and 2002 are presented below:

Interest paid
Income taxes paid (refunded)

2004

YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2002

$
$

474
477

508
123

248
(12)

The 2003 Ocean merger and 2002 Mitchell merger 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

(IN MILLIONS)

3,546
64
124
2,393
954
7,081

1,512
—
27
824
798
3,161

DECEMBER 31,

2004

2003

(IN MILLIONS)

946
159
162
60
1,327
(7)
1,320

668
124
106
59
957
(11)
946

PROPERTY AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS

Property and equipment included the following:

Oil and gas properties:

Subject to amortization
Not subject to amortization
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

DECEMBER 31,

2004

2003

(IN MILLIONS)

27,257
3,187
(12,410)
18,034
1,670
(358)
1,312

23,590
3,336
(9,967)
16,959
1,620
(245)
1,375

19,346

18,334

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.

D I S C O V E R I N G D E V O N 69

Notes To Consolidated Financial Statements

The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2004:

Acquisition costs
Exploration costs
Development costs
Capitalized interest

Total oil and gas properties costs not

subject to amortization

COSTS INCURRED IN

2004

2003

2002
(IN MILLIONS)

PRIOR TO
2002

174
279
32
66

551

674
246
61
37

1,018

471
47
4
2

524

1,086
6
—
2

1,094

Total

2,405
578
97
107

3,187

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 a 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 for the years ended
December 31, 2004 and 2003.

Asset retirement obligation as of beginning of year

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 end of year
Less current portion
Asset retirement obligation, long-term

YEAR ENDED DECEMBER 31,

2004

2003

(IN MILLIONS)

671
—
—
51
(42)
(4)
44
19

739
46
693

—
453
134
48
(37)
(4)
36
41

671
42
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 14.2

million 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 value,
which was $47.69 per share, or an aggregate value of $677 million. Since then, as the ChevronTexaco shares have ﬂuctuated in market value,
the value of the shares on Devon’s balance sheet has been adjusted to the applicable market value. Through September 30, 2002, any
decreases in the value of the ChevronTexaco common shares were determined by Devon to be temporary in nature. Therefore, the changes
in value were recorded directly to stockholders’ equity and were not recorded in Devon’s results of operations through September 30, 2002.
The determination that a decline in value of the ChevronTexaco shares is temporary or other than temporary is subjective and
inﬂuenced by many factors. Among these factors are the signiﬁcance of the decline as a percentage of the original cost, the length of time the
stock price has been below original cost, the performance of the stock price in relation to the stock price of its competitors within the
industry and the market in general, and whether the decline is attributable to speciﬁc adverse conditions affecting ChevronTexaco.

Beginning in July 2002, the market value of ChevronTexaco common stock began a signiﬁcant decline. The price per share decreased
from $44.25 at June 30, 2002, to $34.63 per share at September 30, 2002, and to $33.24 per share at December 31, 2002. The 2002 year-
end price of $33.24 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

70 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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.

The share price of ChevronTexaco common stock has increased to $43.19 at December 31, 2003 and $52.51 at December 31, 2004.

As a result, the market value of Devon’s investment in ChevronTexaco common stock increased $273 million from December 31, 2002 to
December 31, 2004. The changes in the value of the shares since December 31, 2002, net of applicable taxes, have been recorded directly to
accumulated other comprehensive income in 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 (retired in 2004)
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 (ﬁrst put date June 26, 2005)

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 ($175 million Canadian)
10.25% due November 1, 2005
2.75% due August 1, 2006
6.55% due August 2, 2006 ($200 million Canadian)
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 premium on other debentures and notes

Less amount classiﬁed as current
Long-term debt

DECEMBER 31,

2004

2003

(IN MILLIONS)

—
—
—

444
316
(68)

419

—
—
125
145
236
500
166
400
177
400
1,750
350
125
150
1,250
1,000
3
9
67
7,964
933
7,031

—
—
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

Maturities of long-term debt as of December 31, 2004, excluding the $1 million of net discounts and the $9 million fair value

adjustment, are as follows (in millions):

2005
2006
2007
2008
2009
2010 and thereafter

Total

926
667
400
761
177
5,025
7,956

D I S C O V E R I N G D E V O N 71

Notes To Consolidated Financial Statements

Credit Facilities with Banks

Devon has a $1.5 billion ﬁve-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). The Senior Credit
Facility includes (i) a ﬁve-year revolving Canadian subfacility in a maximum amount of U.S. $500 million and (ii) a $1 billion sublimit for
the issuance of letters of credit, including letters of credit under the Canadian subfacility.

The Senior Credit Facility matures on April 8, 2009, and all amounts outstanding will be due and payable at that time unless the

maturity is extended. Prior to each April 8 anniversary date, Devon has the option to extend the maturity of the Senior Credit Facility for
one year, subject to the approval of the lenders. Devon has obtained lender approval to extend the current maturity date of April 8, 2009 to
April 8, 2010. This maturity date extension will be effective April 8, 2005 provided Devon has not experienced a “material adverse effect,” as
deﬁned in the Senior Credit Facility agreement, at that date.

Amounts borrowed under the Senior Credit Facility may, at the election of Devon, bear interest at various ﬁxed rate options for

periods of up to twelve months. Such rates are generally less than the prime rate. Devon may also elect to borrow at the prime rate. The
Senior Credit Facility currently provides for an annual facility fee of $1.9 million that is payable quarterly in arrears.

The agreement governing the Senior Credit Facility contains certain covenants and restrictions, including a maximum allowed debt-to-

capitalization ratio of 65% as deﬁned in the agreement. At December 31, 2004, Devon was in compliance with such covenants and
restrictions. Devon’s debt-to-capitalization ratio at December 31, 2004, as calculated pursuant to the terms of the agreement, was 33.0%.

As of December 31, 2004, there were no borrowings under the Senior Credit Facility. The available capacity under the Senior Credit

Facility as of December 31, 2004, net of $226 million of outstanding letters of credit, was approximately $1.3 billion.

Commercial Paper

Devon also has a commercial paper program under which it may borrow up to $725 million. Borrowings under the commercial paper

program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. 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, 2004 and 2003, Devon had no commercial paper debt outstanding.

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. At December 31, 2004,
the call price was 102.0% of principal. 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.

As of December 31, 2004, Devon beneﬁcially owned approximately 14.2 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 18.6566 shares of ChevronTexaco common stock, an exchange rate equivalent to $53.60
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. In accordance with derivative accounting standards, 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 11.5186 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. Therefore, Devon has classiﬁed these debentures as current liabilities in the December
31, 2004 consolidated balance sheet. 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.

72 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2004, as listed in the table

presented at the beginning of this note.

Ocean Debt In connection with the Ocean merger, Devon assumed $1.8 billion of debt. The table below summarizes the debt

assumed which remains outstanding, the fair value of the debt at April 25, 2003, and the effective interest rate of the debt assumed after
determining the fair values of the respective notes using April 25, 2003, 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

7.625% due July 2005 (principal of $125 million)
4.375% due October 2007 (principal of $400 million)
7.250% due October 2011 (principal of $350 million)
8.250% due July 2018 (principal of $125 million)
7.500% due September 2027 (principal of $150 million)

FAIR VALUE OF
DEBT ASSUMED
(IN MILLIONS)

EFFECTIVE RATE OF
DEBT ASSUMED

$
$
$
$
$

139
410
406
147
169

3.0%
3.8%
4.9%
5.5%
6.5%

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
DEBT ASSUMED
(IN MILLIONS)

EFFECTIVE RATE OF
DEBT ASSUMED

$
$
$

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 Corporation, U.L.C. (“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.

D I S C O V E R I N G D E V O N 73

Notes To Consolidated Financial Statements

Interest Expense

Following are the components of interest expense for the years 2004, 2003 and 2002:

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

2004

YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2002

513
2
2
22
(70)
—
6
475

531
3
1
12
(50)
—
5
502

499
13
2
8
(4)
8
7
533

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, $22 million, $69 million and $1 million was recorded as a reduction of expense in 2004, 2003 and 2002, respectively.

INCOME TAXES

At December 31, 2004, Devon had the following net operating loss carryforwards which are available to reduce future

taxable income in the jurisdiction where the net operating loss was incurred. These carryforwards will result in a future tax

reduction based upon the future tax rate applicable to the taxable income that is ultimately offset by the net operating loss carryforward.

JURISDICTION

U.S. federal
Various U.S. states
Canada
Azerbaijan

YEARS OF
EXPIRATION

CARRYFORWARD
AMOUNTS
(IN MILLIONS)

2020 – 2022
2005 – 2022
2006 – 2014
Indeﬁnite

$
$
$
$

383
265
524
75

Additionally, at December 31, 2004, Devon had $29 million of U.S. minimum tax credit carryforwards which have no expiration and

are available to reduce future income taxes. The net operating loss and minimum tax credit carryforward amounts have been recognized for
ﬁnancial purposes to reduce the deferred tax liability at December 31, 2004.

74 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

The earnings (loss) before income taxes and the components of income tax expense (beneﬁt) for the years 2004, 2003 and 2002

were as follows:

Earnings (loss) from continuing operations before income taxes:

2004

YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2002

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)

2,264
598
431
3,293

473
10
49
220
752

219
21
149
(34)
355

Total income tax expense (beneﬁt)

1,107

1,603
603
39
2,245

125
6
(9)
71
193

360
17
(16)
(40)
321

514

354
(515)
27
(134)

(34)
11
28
18
23

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

(193)

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:

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 reductions
Other
Total income tax expense (beneﬁt)

2004

YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2002

1,153
2
(5)
—
20
(30)
(36)
3
1,107

786
1
(5)
—
15
(78)
(218)
13
514

(47)
—
(5)
(19)
7
(121)
—
(8)
(193)

During 2004 and 2003, total income tax expense was reduced by the effects of Canadian statutory rate reductions. As presented in the

table above, these rate reductions resulted in a $36 million and $218 million beneﬁt being recorded in 2004 and 2003, respectively, related
to the lower tax rates being applied to deferred tax liabilities outstanding as of the beginning of the year.

D I S C O V E R I N G D E V O N 75

Notes To Consolidated Financial Statements

The tax effects of temporary differences that gave rise to signiﬁcant portions of the deferred tax assets and liabilities at December 31,

2004 and 2003 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,

2004

2003

(IN MILLIONS)

336
29
157
252
52
130
956

(5,366)
(231)
(149)
(10)
(5,756)
(4,800)

416
56
44
281
85
139
1,021

(5,052)
(190)
(102)
(47)
(5,391)
(4,370)

As shown in the above table, Devon has recognized $956 million of deferred tax assets as of December 31, 2004. Such amount
consists of $336 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 2020, state net operating loss carryforwards which expire primarily between
2005 and 2022, Canadian net operating loss carryforwards which expire primarily between 2006 and 2014, and Azerbaijani net operating
loss carryforwards and U.S. 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 2005 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 outstanding. In January 2004, these shares of convertible preferred stock were canceled and converted to 2,197,160 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 $26.20 for 20 consecutive trading days.

STOCKHOLDERS’ EQUITY

The authorized capital stock of Devon consists of 800 million shares of common stock, par value $0.10 per share 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 32 million exchangeable shares issued on December 10, 1998, in connection with the Northstar Energy Corporation
combination. These shares were essentially equivalent to Devon common stock and were exchangeable at any time, on a one-for-one basis,
for common shares of Devon at the holder’s option. The last remaining exchangeable shares outstanding were exchanged for Devon common
stock on August 27, 2004.

76 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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. On
April 25, 2003, the board increased the designated shares from 2.0 million to 2.9 million. At December 31, 2004, 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 $1.00 or 200 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 200 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.

On September 27, 2004, Devon announced a stock buyback program to repurchase up to 50 million shares of its common stock.

During 2004, Devon repurchased 5 million shares at a total cost of $189 million, or $37.78 per share. Devon intends to continue
repurchasing its shares in the open market and in privately negotiated transactions, depending upon market conditions. The stock repurchase
program may be discontinued at any time.

The following is a summary of the changes in Devon’s common shares outstanding for 2004, 2003 and 2002:

Shares outstanding, beginning of year
Exercise of stock options
Shares repurchased and retired
Grant of restricted stock
Conversion of subsidiary’s preferred stock
Issuance of common stock
Shares outstanding, end of year

2004

2003
(IN MILLIONS)

472
13
(5)
2
2
—
484

314
10
—
—
—
148
472

2002

252
2
—
—
—
60
314

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, 2004,
there were 202,000 and 8,774,000 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 25,000,000 shares of Devon common stock have been reserved
for issuance pursuant to the plan. Of these shares, no more than 5,000,000 shares may be granted as restricted stock, performance bonuses
and performance units. During 2004 and 2003, 1,703,000 and 1,306,000 restricted stock awards, respectively, were granted which are
subject to pro rata vesting over a four-year period. These awards had an aggregate fair value of $66 million and $34 million in 2004 and
2003, respectively, 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, 2004, there were 5,906,000 options outstanding under the 2003
Plan. There were 16,022,000 options available for future grants as of December 31, 2004.

In addition to the stock options outstanding under the 1993 Plan, 1997 Plan and 2003 Plan there were approximately 2,739,000,
363,000, 200,000 and 1,591,000 stock options outstanding at the end of 2004 that were assumed as part of the Ocean merger, the Mitchell
merger, the Santa Fe Snyder merger and the PennzEnergy merger, respectively.

D I S C O V E R I N G D E V O N 77

Notes To Consolidated Financial Statements

A summary of the status of Devon’s stock option plans as of December 31, 2002, 2003 and 2004, and changes during each of the

years then ended, is presented below.

OPTIONS OUTSTANDING

OPTIONS EXERCISABLE

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

Options granted
Options exercised
Options forfeited

Balance at December 31, 2004

NUMBER
OUTSTANDING
(IN THOUSANDS)

16,368
5,614
3,108
(1,799)
(830)

22,461
3,008
15,852
(9,732)
(899)

30,690
3,176
(13,479)
(612)

19,775

WEIGHTED
AVERAGE
EXERCISE
PRICE

$
$
$
$
$

$
$
$
$

20.54
22.88
13.41
14.67
23.56

20.50
26.38
19.84
16.75
26.10

21.76
37.76
19.84
24.96

25.54

NUMBER
EXERCISABLE
(IN THOUSANDS)

WEIGHTED
AVERAGE
EXERCISE
PRICE

11,032

20.97

13,983

20.03

22,920

21.30

13,027

23.27

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

as of December 31, 2004:

RANGE OF EXERCISE PRICES

$4.84 - $17.43
$17.90 - $23.04
$23.05 - $23.05
$23.14 - $26.43
$26.50 - $38.45
$38.61 - $44.83

OPTIONS OUTSTANDING

WEIGHTED
AVERAGE
REMAINING
LIFE

WEIGHTED
AVERAGE
EXERCISE
PRICE

NUMBER
OUTSTANDING
(IN THOUSANDS)

3,765
2,158
3,784
4,829
4,922
317
19,775

4.63 Years
4.64 Years
5.94 Years
5.24 Years
4.82 Years
2.88 Years
5.05 Years

$
$
$
$
$
$
$

15.75
20.68
23.05
25.95
35.70
40.86
25.54

OPTIONS EXERCISABLE

NUMBER
EXERCISABLE
(IN THOUSANDS)

3,316
2,108
2,170
3,090
2,040
303
13,027

WEIGHTED
AVERAGE
EXERCISE
PRICE

$
$
$
$
$
$
$

15.52
20.68
23.05
25.73
32.43
40.89
23.27

Shareholder Rights Plan

Under Devon’s shareholder rights plan, stockholders have one half of one right for each share of common stock held. The rights become
exercisable and separately transferable ten business days after (a) an announcement that a person has acquired, or obtained the right to acquire,
15% or more of the voting shares outstanding, or (b) commencement of a tender or exchange offer that could result in a person owning 15%
or more of the voting shares outstanding.

Each right entitles its holder (except a holder who is the acquiring person) to purchase either (a) 1/100 of a share of Series A Preferred
Stock for $185.00, 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 August 17, 2009. The rights may be redeemed by Devon for $.01 per right until the

rights become exercisable.

Dividends

Dividends on Devon’s common stock were paid in 2004 at a per share rate of $0.05 per quarter. Dividends on Devon’s common stock

were paid in 2003 and 2002 at a per share rate of $0.025 per quarter.

78 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

FINANCIAL INSTRUMENTS

(liabilities) at December 31, 2004 and 2003.

The following table presents the carrying amounts and estimated fair values of Devon’s ﬁnancial instrument assets

2004

CARRYING
AMOUNT

FAIR
VALUE

2003

CARRYING
AMOUNT

FAIR
VALUE

(IN MILLIONS)

Investment in ChevronTexaco Corporation common stock
Oil and gas price hedge agreements
Interest rate swap agreements
Electricity hedge agreements
Embedded option in exchangeable debentures
Long-term debt
Preferred stock of a subsidiary

$
$
$
$
$
$
$

745
(395)
—
—
(67)
(7,964)
—

745
(395)
—
—
(67)
(9,046)
—

613
(186)
18
(1)
(9)
(8,918)
(55)

613
(186)
18
(1)
(9)
(9,680)
(63)

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, short-term investments, 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, 2004
and 2003.

Investment in ChevronTexaco Corporation common stock — The fair value of this investment is based on a quoted market price.

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 internal discounted cash ﬂow calculations, using

market quotes of future interest rates, or quotes obtained from counterparties.

Electricity Hedge Agreements — The fair values of the electricity hedges are based on internal discounted cash ﬂow calculations.

Embedded Option in Exchangeable Debentures — The fair value of the embedded option is based on a quote obtained from brokers.

Long-term Debt — The fair values of the ﬁxed-rate long-term debt are 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, 2004 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 2005. These

swaps will result in the ﬁxed prices included below. Where necessary, the oil and gas prices related to these swaps have been adjusted for
certain transportation costs that are netted against the price recorded by Devon, and the gas price has also been adjusted for the Btu content
of the production that has been hedged.

D I S C O V E R I N G D E V O N 79

Notes To Consolidated Financial Statements

YEAR

2005

YEAR

2005

OIL PRODUCTION

BBLS/DAY

22,000

WEIGHTED AVERAGE
PRICE PER BBL

$ 26.84

GAS PRODUCTION

MCF/DAY

WEIGHTED AVERAGE
PRICE PER MCF

7,343

3.40

Costless Price Collars

Devon has also entered into costless price collars that set a ﬂoor and ceiling price for a portion of its 2005 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. As long as Devon meets the ongoing requirements of hedge accounting for its derivatives, 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 heavy or 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 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.

The ﬂoor and ceiling prices shown in the following table are weighted averages of the various collars. The international oil prices
shown in the following table have been adjusted to a NYMEX-based price, using Devon’s estimates of 2005 differentials between NYMEX
and the Brent price upon which the collars are based.

The natural gas prices shown in the following table 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
collars are based on various regional ﬁrst-of-the-month price indices as published monthly by Inside FERC.

YEAR

2005

YEAR

2005

OIL PRODUCTION

BBLS/DAY

WEIGHTED AVERAGE

FLOOR PRICE
PER BBL

CEILING PRICE
PER BBL

50,000

22.45

28.45

GAS PRODUCTION

MMBTU/DAY

WEIGHTED AVERAGE

FLOOR PRICE
PER MMBTU

CEILING PRICE
PER MMBTU

94,548

3.83

7.21

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 $104 million in 2005 and 2006 and 6.3% on a notional
amount of $32 million in 2007. Following is a table summarizing the ﬁxed-to-ﬂoating interest rate swaps with the related debt instrument
and notional amounts.

80 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

DEBT INSTRUMENT

NOTIONAL AMOUNT
(IN MILLIONS)

FLOATING RATE

7.625% senior notes due in 2005
10.25% bonds due in 2005
2.75% notes due in 2006
6.55% senior notes due 2006
4.375% senior notes due in 2007
6.75% senior notes due 2011

$
$
$
$
$
$

125
235
500
166 (1)
400
400

LIBOR plus 237 basis points
LIBOR plus 711 basis points
LIBOR less 26.8 basis points
Banker’s Acceptance plus 340 basis points
LIBOR plus 40 basis points
LIBOR plus 197 basis points

(1) Converted from $200 million Canadian dollars at a Canadian-to-U.S. dollar exchange rate of $0.8308 as of December 31, 2004.

RETIREMENT PLANS

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, 2004, the fair value of the Qualiﬁed Plans’ assets was $456 million, which was $11 million more than the related
accumulated beneﬁt obligation. The actual amount of contributions required during future periods 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 $60 million
and $66 million at December 31, 2004, and 2003, 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.

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, 2004, and
2003. 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, 2004, and 2003 was $542 million and $475 million, respectively.

D I S C O V E R I N G D E V O N 81

Notes To Consolidated Financial Statements

Change in beneﬁt obligation:

Beneﬁt obligation at beginning of year
Service cost
Interest cost
Participant contributions
Amendments
Mergers and acquisitions
Special termination beneﬁts
Foreign exchange rate changes
Actuarial loss (gain)
Beneﬁts paid

Beneﬁt obligation at end of year

Actuarial assumptions:

Discount rate
Rate of compensation increase

PENSION BENEFITS

2004

2003

(IN MILLIONS)

OTHER POSTRETIREMENT
BENEFITS

2004

2003

512
15
32
—
1
—
1
2
52
(27)
588

460
12
31
—
1
19
—
4
28
(43)
512

70
1
3
1
(7)
—
—
—
(10)
(8)
50

69
1
4
1
(1)
—
—
—
3
(7)
70

5.74%
4.50%

6.23%
4.88%

5.75%
N/A

6.25%
N/A

For measurement purposes, a 10% annual rate of increase in the per capita cost of covered health care beneﬁts, excluding prescription

beneﬁts, was assumed for 2005. The rate was assumed to decrease one percent annually to 5% in the year 2010 and remain at that level
thereafter. Additionally, an 11% annual rate of increase in the per capita cost of covered prescription beneﬁts was assumed for 2005. The rate
was assumed to decrease approximately one percent annually to 5.25% in the year 2010 and remain at that level thereafter. A one-
percentage-point increase in assumed health care cost trend rates would increase the December 31, 2004 postretirement beneﬁt obligation by
$2 million, while a one-percentage-point decrease in the same rate would decrease the postretirement beneﬁt obligation by $1 million.

Plan Assets

The following table presents the plans’ assets at December 31, 2004 and 2003.

Change in plan assets:

Fair value of plan assets at beginning of year
Actual return on plan assets
Employer contributions
Participant contributions
Transfer to deﬁned contribution plan
Beneﬁts paid
Foreign exchange rate changes

Fair value of plan assets at end of year

PENSION BENEFITS

2004

2003

(IN MILLIONS)

OTHER POSTRETIREMENT
BENEFITS

2004

2003

375
40
70
—
(3)
(27)
1
456

281
70
67
—
(3)
(43)
3
375

—
—
7
1
—
(8)
—
—

—
—
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 $6 million in 2004 and $22 million in 2003 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, 2004, 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.

82 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

The asset allocation for Devon’s retirement plans at December 31, 2004 and 2003, and the target allocation for 2005, by asset

category, follows:

Equity securities
Debt securities
Other

Total

Funded Status

TARGET
ALLOCATION
2005

PERCENTAGE OF PLAN
ASSETS AT YEAR END

2004

2003

80%
20%
0%
100%

82%
17%
1%
100%

79%
19%
2%
100%

The following table presents the funded status of the plans and the net amounts recognized in the consolidated balance sheets at

December 31, 2004, and 2003.

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:

Prepaid cost
Accrued beneﬁt cost
Intangible asset
Accumulated other comprehensive income

Net amount recognized

PENSION BENEFITS

2004

2003

(IN MILLIONS)

OTHER POSTRETIREMENT
BENEFITS

2004

2003

456
588
(132)
155
5
28

98
(96)
4
22
28

375
512
(137)
119
5
(13)

—
(102)
4
85
(13)

—
50
(50)
1
(9)
(58)

—
(58)
—
—
(58)

—
70
(70)
11
(2)
(61)

—
(61)
—
—
(61)

During 2004 and 2003, the pre-tax change in the minimum pension liability increased other comprehensive income by $61 million

and $28 million, respectively. During 2002, the pre-tax change in the minimum pension liability decreased other comprehensive income
by $85 million.

Certain of Devon’s pension and postretirement plans have a projected beneﬁt obligation in excess of plan assets at December 31, 2004

and 2003. 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,
2004
(IN MILLIONS)

2003

$
$

626
441

571
359

Certain of Devon’s pension plans have an accumulated beneﬁt obligation in excess of plan assets at December 31, 2004 and 2003. 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

$
$

98
—

465
359

DECEMBER 31,
2004
(IN MILLIONS)

2003

The plan assets included in the tables above exclude the Supplemental Plan trusts which had a total value of $60 million and $66

million at December 31, 2004 and 2003, respectively.

D I S C O V E R I N G D E V O N 83

Notes To Consolidated Financial Statements

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, 2004, 2003 and 2002.

PENSION BENEFITS
2003

2002

2004

OTHER POSTRETIREMENT
BENEFITS

6
6
6
6
5
24

Employer contributions – 2005

Beneﬁt payments:

2005
2006
2007
2008
2009
2010 – 2014

84 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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 2005, $6 million is expected to be funded from the trusts established for the
Supplemental Plans and $6 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
$5 and $6 million at December 31, 2004 and 2003, respectively.

Devon has a 401(k) Incentive Savings Plan which covers all domestic employees. At its discretion, Devon may match a certain
percentage of the employees’ contributions to the plan. The matching percentage is determined annually by the Board of Directors. Devon’s
matching contributions to the plan were $11 million, $10 million and $8 million for the years ended December 31, 2004, 2003 and 2002,
respectively.

Devon has deﬁned contribution pension plans for its Canadian employees. Devon makes a contribution to each employee which is
based upon the employee’s base compensation and classiﬁcation. Such contributions are subject to maximum amounts allowed under the
Income Tax Act (Canada). Devon also has a savings plan for its Canadian employees. Under the savings plan, Devon contributes a base
percentage amount to all employees and the employee may elect to contribute an additional percentage amount (up to a maximum amount)
which is matched by additional Devon contributions. During 2004, 2003 and 2002, Devon’s combined contributions to the Canadian
deﬁned contribution plan and the Canadian savings plan were $9 million, $8 million and $8 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, 2004, Devon’s consolidated balance sheet included $7 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.

D I S C O V E R I N G D E V O N 85

Notes To Consolidated Financial Statements

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. Trial is set for February 2007 if the suit continues to advance. 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. 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.

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 (“IRS”) recently examined the 1998 income tax return of PennzEnergy’s predecessor, and the IRS
formally notiﬁed Devon in April 2004 that it disagreed with certain tax treatments of the exchangeable debentures and similar exchangeable
debentures retired in 1998. Devon did not agree with the IRS positions and contested the claim of additional taxes. In June 2004, Devon
formally protested the IRS notice and requested a conference with the IRS Appeals Office. A preliminary appeals conference was held in
October 2004, and additional appeals meetings were held in November and December 2004. This matter was resolved in February 2005,
when the IRS agreed with Devon and concluded that no taxes were due.

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 $49 million, $51 million and $37 million in 2004, 2003 and
2002, 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 $17
million and $11 million in 2004 and 2003, respectively. 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 facilities (“FPSO”) 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 2009. Total rental expense
included in lease operating expenses under these operating leases was $20 million and $6 million in 2004 and 2003, respectively.

86 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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, 2004:

YEAR ENDING DECEMBER 31,

2005
2006
2007
2008
2009

Thereafter

Total minimum lease payments

OFFICE AND
EQUIPMENT
LEASES

SPAR
LEASES
(IN MILLIONS)

FPSO
LEASES

35
30
28
25
23
69
210

15
15
15
15
14
228
302

20
20
20
19
13
—
92

REDUCTION OF CARRYING VALUE OF OIL AND GAS PROPERTIES

Under the full cost method of accounting, the net book value of oil and gas properties, less related deferred income taxes,
may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas
properties, excluding future cash outﬂows associated with settling asset retirement obligations included in the net book value of 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, prices and costs used are those as of the end of the appropriate quarterly period. These prices are not changed except where
different prices are ﬁxed and determinable from applicable contracts for the remaining term of those contracts. Devon has entered into
various derivative instruments that are accounted for as cash ﬂow hedges. These instruments, which consist of price swaps and costless price
collars, and the related future production volumes, are discussed in Note 12. The effect of these hedges has been considered in calculating the
full cost ceiling limitations as of December 31, 2004. These hedges reduced the full cost ceiling limitations for the United States, Canada and
Equatorial Guinea as of the end of 2004 by $102 million, $77 million and $76 million, respectively. However, the 2004 capitalized costs in
these countries did not exceed the related ceiling limitations, with or without the effects of the hedges.

The net book value, less related deferred tax liabilities, is compared to the ceiling on a quarterly and annual basis. Any excess of the net

book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.

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 and 2002, Devon reduced the carrying value of its oil and gas properties by $68 million and $651 million, respectively,

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

Canada
International

Total

YEAR ENDED DECEMBER 31,

2003

2002

NET OF
TAXES

GROSS

(IN MILLIONS)

—
36
36

651
—
651

NET OF
TAXES

371
—
371

GROSS

—
68
68

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.

D I S C O V E R I N G D E V O N 87

Notes To Consolidated Financial Statements

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.

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.

As a result, Devon reclassiﬁed its Indonesian, Argentine and Egyptian activities as discontinued operations. This reclassiﬁcation

affects the 2002 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 2004 and 2003. The revenues from these discontinued operations for the
year ended December 31, 2002 (in millions) are presented below:

Oil sales
Gas sales
NGL sales

Total revenues

SEGMENT INFORMATION

72
7
1
80

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 2004, 2003 and 2002. The revenues reported are all from

external customers.

As of December 31, 2004
Current assets
Property and equipment, net of accumulated
depreciation, depletion and amortization

Goodwill
Other assets

Total assets

Current liabilities
Long-term debt
Asset retirement obligation, long-term
Other liabilities
Deferred income taxes
Stockholders’ equity

Total liabilities and stockholders’ equity

88 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

2,038

11,011
3,061
1,123
17,233

1,933
3,496
412
400
2,695
8,297
17,233

1,018

5,741
2,508
19
9,286

800
3,535
250
21
1,714
2,966
9,286

527

2,594
68
28
3,217

367
—
31
17
391
2,411
3,217

3,583

19,346
5,637
1,170
29,736

3,100
7,031
693
438
4,800
13,674
29,736

Year Ended December 31, 2004
Revenues:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues
Operating costs and expenses:
Lease operating expenses
Production taxes
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization of oil and gas properties
Depreciation and amortization of non-oil and gas properties
Accretion of asset retirement obligation
General and administrative expenses

Total operating costs and expenses

Earnings from operations
Other income (expenses):

Interest expense
Effects of changes in foreign currency exchange rates
Change in fair value of derivative ﬁnancial instruments
Other income

Net other income (expenses)

Earnings before income taxes
Income tax expense (beneﬁt):

Current
Deferred

Total income tax expense

Net earnings

Capital expenditures

As of December 31, 2003
Current assets
Property and equipment, net of accumulated
depreciation, depletion and amortization

Goodwill
Other assets

Total assets

Current liabilities
Long-term debt
Asset retirement obligation, long-term
Other liabilities
Preferred stock of a subsidiary
Deferred income taxes
Stockholders’ equity

Total liabilities and stockholders’ equity

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

976
3,261
405
1,688
6,330

714
220
1,333
1,242
130
27
221
3,887
2,443

(197)
—
(63)
81
(179)
2,264

483
240
723
1,541

1,785

299
1,437
143
13
1,892

438
5
6
522
14
15
56
1,056
836

(278)
22
1
17
(238)
598

49
149
198
400

975

927
34
6
—
967

128
30
—
377
5
2
—
542
425

—
1
—
5
6
431

220
(34)
186
245

343

2,202
4,732
554
1,701
9,189

1,280
255
1,339
2,141
149
44
277
5,485
3,704

(475)
23
(62)
103
(411)
3,293

752
355
1,107
2,186

3,103

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

1,411

10,753
3,073
908
16,145

1,320
4,810
386
371
55
2,471
6,732
16,145

643

4,900
2,336
27
7,906

458
3,770
218
20
—
1,433
2,007
7,906

310

2,681
68
52
3,111

293
—
25
10
—
466
2,317
3,111

2,364

18,334
5,477
987
27,162

2,071
8,580
629
401
55
4,370
11,056
27,162

D I S C O V E R I N G D E V O N 89

Notes To Consolidated Financial Statements

Year Ended December 31, 2003
Revenues:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

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

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

861
2,652
289
1,443
5,245

617
194
1,165
1,084
111
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

392
3
9
389
10
13
43
—
—
859
812

(285)
—
69
(1)
8
(209)

603

(9)
(16)
(25)
628
5
633

704

409
23
4
—
436

69
7
—
195
4
1
12
—
111
399
37

(6)
—
—
—
8
2

71
(40)
31
8
—
8

304

1,588
3,897
407
1,460
7,352

1,078
204
1,174
1,668
125
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

90 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Year Ended December 31, 2002
Revenues:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues
Operating costs and expenses:
Lease operating expenses
Production taxes
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization of oil and gas properties
Depreciation and amortization of non-oil and gas properties
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

U.S.

CANADA

INTERNATIONAL

TOTAL

(IN MILLIONS)

524
1,403
192
985
3,104

453
104
800
737
97
166
—
2,357
747

(235)
—
31
(205)
16
(393)
354

(23)
42
19
335

—
—
—
335

2,797

331
730
83
14
1,158

310
7
8
364
7
40
651
1,387
(229)

(295)
1
(3)
—
11
(286)
(515)

28
(253)
(225)
(290)

—
—
—
(290)

532

54
—
—
—
54

12
—
—
5
1
13
—
31
23

(3)
—
—
—
7
4
27

18
(5)
13
14

54
9
45
59

909
2,133
275
999
4,316

775
111
808
1,106
105
219
651
3,775
541

(533)
1
28
(205)
34
(675)
(134)

23
(216)
(193)
59

54
9
45
104

3,426

D I S C O V E R I N G D E V O N 91

Notes To Consolidated Financial Statements

SUPPLEMENTAL INFORMATION ON OIL AND GAS OPERATIONS (UNAUDITED)

The following supplemental unaudited information regarding the oil and gas activities of Devon is presented pursuant
to the disclosure requirements promulgated by the Securities and Exchange Commission and SFAS No. 69, Disclosures About Oil and Gas
Producing Activities.

Costs Incurred

The following tables reﬂect the costs incurred in oil and gas property acquisition, exploration, and development activities:

TOTAL
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

4,343
1,063
87
1,150
714
1,864
8,071

DOMESTIC
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2,697
551
48
599
343
1,193
4,832

CANADA
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

26
—
39
39
214
491
770

2002

1,538
639
64
703
383
1,140
3,764

2002

1,536
639
27
666
161
808
3,171

2002

2
—
28
28
207
299
536

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2002

1,620
512
—
512
157
180
2,469

—
—
9
9
15
33
57

2004

38
—
141
141
735
1,938
2,852

2004

27
—
75
75
335
1,163
1,600

2004

11
—
52
52
272
625
960

2004

—
—
14
14
128
150
292

Property acquisition costs:

Proved properties
Unproved properties – business combinations
Unproved properties – other acquisitions

Total unproved properties

Exploration costs
Development costs

Costs incurred

Property acquisition costs:

Proved properties
Unproved properties – business combinations
Unproved properties – other acquisitions

Total unproved properties

Exploration costs
Development costs

Costs incurred

Property acquisition costs:

Proved properties
Unproved properties – business combinations
Unproved properties – other acquisitions

Total unproved properties

Exploration costs
Development costs

Costs incurred

Property acquisition costs:

Proved properties
Unproved properties – business combinations
Unproved properties – other acquisitions

Total unproved properties

Exploration costs
Development costs

Costs incurred

92 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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 $172 million, $140 million and $97 million in the years 2004, 2003 and 2002, respectively. Also, 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 $70 million, $50 million and $4 million in
the years 2004, 2003 and 2002, respectively.

The preceding Total and International cost incurred tables exclude $16 million in 2002 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.

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,
2003
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

2002

2004

Oil, gas and NGL 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
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

Oil, gas and NGL 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

Income tax expense
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

7,488
(1,535)
(2,141)
(44)

(38)
—
(1,288)
2,442

8.54

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

DOMESTIC
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

2002

2004

4,642
(934)
(1,242)
(27)

(22)
(827)
1,590

8.23

3,802
(811)
(1,084)
(22)

(27)
(775)
1,083

7.42

2,119
(557)
(737)
—

(14)
(295)
516

6.22

D I S C O V E R I N G D E V O N 93

Notes To Consolidated Financial Statements

Oil, gas and NGL 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

Oil, gas and NGL 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
Results of operations for oil and gas producing activities
Depreciation, depletion and amortization per equivalent

barrel of production

CANADA
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

2002

2004

1,879
(443)
(522)
(15)

(16)
—
(275)
608

8.00

1,654
(395)
(388)
(13)

(15)
—
(89)
754

6.17

1,144
(317)
(364)
—

(14)
(651)
74
(128)

5.39

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS, EXCEPT PER EQUIVALENT BARREL AMOUNTS)

2002

2004

967
(158)
(377)
(2)

—
—
(186)
244

436
(76)
(196)
(1)

(6)
(111)
(31)
15

54
(12)
(5)
—

(1)
—
(13)
23

10.88

10.52

2.40

The preceding Total and International results of oil and gas producing activities tables exclude $19 million in 2002 related to

discontinued operations.

Quantities of Oil and Gas Reserves

Set forth below is a summary of the reserves which were evaluated, either by preparation or audit, by independent petroleum

consultants for each of the years ended 2004, 2003 and 2002.

2004

2003

2002

PREPARED

AUDITED

PREPARED

AUDITED

PREPARED

AUDITED

Domestic
Canada
International

16%
22%
98%

61%
—
—

33%
28%
98%

37%
—
—

12%
31%
100%

61%
—
—

“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. An audit is an examination of a company’s proved oil and gas reserves and net cash ﬂow by an independent petroleum consultant
that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated
and presented in conformity with generally accepted petroleum engineering and evaluation principles.

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 each of the years presented. The International reserves were evaluated by the independent petroleum consultants of
Ryder Scott Company, L.P. in each of the years presented.

94 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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, 2004.

Proved reserves as of December 31, 2001

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2004
Proved developed reserves as of:

December 31, 2001
December 31, 2002
December 31, 2003
December 31, 2004

Proved reserves as of December 31, 2001

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2004
Proved developed reserves as of:

December 31, 2001
December 31, 2002
December 31, 2003
December 31, 2004

OIL
(MMBBLS)

527
(19)
9
36
13
(42)
(80)
444
(4)
(5)
29
262
(62)
(3)
661
(84)
19
78
1
(78)
(1)
596

298
260
408
411

OIL
(MMBBLS)

191
13
(5)
10
12
(24)
(50)
147
3
(9)
12
92
(31)
(2)
212
5
2
16
—
(31)
(1)
203

167
135
171
168

GAS
(BCF)

5,024
27
(108)
570
1,723
(761)
(639)
5,836
64
(73)
834
1,650
(863)
(132)
7,316
39
30
988
14
(891)
(2)
7,494

3,911
4,618
5,980
6,219

GAS
(BCF)

2,399
74
(48)
344
1,722
(482)
(457)
3,552
93
(36)
510
1,474
(589)
(120)
4,884
8
62
578
8
(602)
(2)
4,936

1,988
2,802
3,935
4,105

TOTAL

NATURAL GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

108
2
(2)
11
105
(19)
(13)
192
2
(2)
20
19
(22)
—
209
1
21
25
—
(24)
—
232

88
150
179
204

1,472
(12)
(11)
142
405
(188)
(199)
1,609
8
(19)
188
556
(228)
(25)
2,089
(76)
45
268
3
(251)
(1)
2,077

1,038
1,180
1,584
1,652

DOMESTIC

NATURAL GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

52
3
(1)
6
105
(14)
(5)
146
3
(4)
14
19
(17)
—
161
1
23
16
—
(19)
—
182

48
117
136
161

642
29
(14)
73
404
(118)
(131)
885
21
(19)
111
357
(146)
(22)
1,187
8
35
129
1
(151)
(1)
1,208

546
719
964
1,014

D I S C O V E R I N G D E V O N 95

Notes To Consolidated Financial Statements

Proved reserves as of December 31, 2001

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2004
Proved developed reserves as of:

December 31, 2001
December 31, 2002
December 31, 2003
December 31, 2004

Proved reserves as of December 31, 2001

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2002

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2003

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2004
Proved developed reserves as of:

December 31, 2001
December 31, 2002
December 31, 2003
December 31, 2004

96 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

OIL
(MMBBLS)

166
(2)
4
26
1
(16)
(30)
149
1
(5)
16
2
(14)
(1)
148
(43)
5
50
1
(14)
—
147

124
119
123
123

GAS
(BCF)

2,625
(47)
(60)
226
1
(279)
(182)
2,284
(28)
(5)
324
1
(267)
(12)
2,297
32
(46)
410
6
(279)
—
2,420

1,923
1,816
1,964
2,043

CANADA

NATURAL GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

56
(1)
(1)
5
—
(5)
(8)
46
(1)
2
6
—
(5)
—
48
—
(2)
9
—
(5)
—
50

40
33
43
43

660
(11)
(7)
69
1
(68)
(68)
576
(5)
(4)
76
2
(63)
(3)
579
(38)
(5)
127
2
(65)
—
600

485
455
493
507

INTERNATIONAL

OIL
(MMBBLS)

GAS
(BCF)

NATURAL GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

170
(30)
10
—
—
(2)
—
148
(8)
9
1
168
(17)
—
301
(46)
12
12
—
(33)
—
246

7
6
114
120

—
—
—
—
—
—
—
—
(1)
(32)
—
175
(7)
—
135
(1)
14
—
—
(10)
—
138

—
—
81
71

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

—
—
—
—

170
(30)
10
—
—
(2)
—
148
(8)
4
1
197
(19)
—
323
(46)
15
12
—
(35)
—
269

7
6
127
131

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, 2001
December 31, 2002

Proved developed reserves as of:

December 31, 2001
December 31, 2002

OIL
(MMBBLS)

GAS
(BCF)

NATURAL GAS
LIQUIDS
(MMBBLS)

TOTAL
(MMBOE)

59
1

26
—

453
—

37
—

13
—

—
—

147
1

32
—

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

TOTAL
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2004

67,035

60,562

(4,250)
(18,395)
(14,241)
30,149
(14,064)
16,085

(3,693)
(16,232)
(12,078)
28,559
(12,638)
15,921

2002

38,399

(2,053)
(9,076)
(8,737)
18,533
(8,168)
10,365

DOMESTIC
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2004

2002

39,214

36,602

20,571

(2,208)
(12,093)
(7,989)
16,924
(7,550)
9,374

(2,028)
(10,788)
(6,848)
16,938
(7,435)
9,503

(1,122)
(5,871)
(3,911)
9,667
(4,157)
5,510

CANADA
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2004

2002

18,483

15,517

13,799

(1,353)
(4,285)
(4,200)
8,645
(4,764)
3,881

(1,051)
(3,585)
(3,316)
7,565
(3,442)
4,123

(633)
(2,600)
(3,999)
6,567
(2,677)
3,890

D I S C O V E R I N G D E V O N 97

Notes To Consolidated Financial Statements

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

INTERNATIONAL
YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2004

9,338

(689)
(2,017)
(2,052)
4,580
(1,750)
2,830

8,443

(614)
(1,859)
(1,914)
4,056
(1,761)
2,295

2002

4,029

(298)
(605)
(827)
2,299
(1,334)
965

Future cash inﬂows are computed by applying year-end prices (averaging $34.94 per barrel of oil, $5.46 per Mcf of gas and $22.84 per

barrel of natural gas liquids at December 31, 2004) 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. Such arrangements include derivatives
accounted for as cash ﬂow hedges.

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 $4.3 billion of future development costs, $818 million, $588 million and $388 million are estimated to be spent in 2005, 2006 and
2007, respectively.

Future development costs include not only development costs, but also future dismantlement, abandonment and rehabilitation

costs. Included as part of the $4.3 billion of future development costs are $1.0 billion of future dismantlement, abandonment and
rehabilitation costs.

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.

The preceding Total and International standardized measure of discounted future net cash ﬂows tables exclude $21 million in 2002

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
Oil, gas and NGL sales, 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

2004

YEAR ENDED DECEMBER 31,
2003
(IN MILLIONS)

2002

15,921
(5,915)
2,749

3,103
32

684
(1,132)
(13)
2,265
(1,782)
173
16,085

10,365
(4,562)
2,645

2,218
5,763

1,022
(728)
(307)
1,531
(2,305)
279
15,921

5,015
(2,402)
9,122

1,471
888

175
(61)
(1,879)
692
(2,673)
17
10,365

The preceding table excludes $21 million and $299 million as of December 31, 2002 and 2001, respectively, related to discontinued

operations.

98 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Following is a summary of the unaudited interim results of operations for the years ended December 31, 2004 and 2003.

Oil, gas and NGL sales
Total revenues
Net earnings
Net earnings per common share:

Basic
Diluted

Oil, gas and NGL 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

FIRST
QUARTER

2004
THIRD
SECOND
QUARTER
QUARTER
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

FOURTH
QUARTER

1,821
2,238
494

1.03
1.00

1,842
2,219
502

1.04
1.01

1,859
2,267
517

1.06
1.03

1,966
2,465
673

1.38
1.35

FIRST
QUARTER

2003
THIRD
SECOND
QUARTER
QUARTER
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

FOURTH
QUARTER

1,237
1,671

420
436

1.33

0.05
1.38

1.29

0.05
1.34

1,478
1,813

356
356

0.84

—
0.84

0.81

—
0.81

1,613
1,948

412
412

0.88

—
0.88

0.85

—
0.85

1,564
1,921

543
543

1.16

—
1.16

1.13

—
1.13

$
$
$

$
$

FULL
YEAR

7,488
9,189
2,186

4.51
4.38

FULL
YEAR

5,892
7,352

1,731
1,747

4.12

0.04
4.16

4.00

0.04
4.04

The second and fourth quarters of 2004 include a $28 million and $8 million income tax beneﬁt, respectively, due to statutory rate

reductions of Canadian tax rates. The per share effect of these tax beneﬁts were $0.06 and $0.01 in the second and fourth quarters of 2004,
respectively.

The fourth quarter of 2003 includes a $218 million income tax beneﬁt due to a statutory rate reduction of Canadian tax rates. The per
share effect of this tax beneﬁt was $0.45. 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 $0.16 per share.

D I S C O V E R I N G D E V O N 99

Reports on Internal Control Over Financial Reporting

Management’s Annual Report on Internal Control Over Financial Reporting

Devon's management is responsible for establishing and maintaining adequate internal control over ﬁnancial reporting for Devon, as

such term is deﬁned in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Under the supervision and with the
participation of Devon's management, including our principal executive and principal ﬁnancial officers, Devon conducted an evaluation of
the effectiveness of its internal control over ﬁnancial reporting based on the framework in Internal Control — Integrated Framework issued by
the Committee of Sponsoring Organizations of the Treadway Commission (the "COSO Framework"). Based on this evaluation under the
COSO Framework which was completed on February 18, 2005, management concluded that its internal control over ﬁnancial reporting
was effective as of December 31, 2004.

Management's assessment of the effectiveness of Devon's internal control over ﬁnancial reporting as of December 31, 2004 has been
audited by KPMG LLP, an independent registered public accounting ﬁrm who audited Devon's consolidated ﬁnancial statements as of and
for the year ended December 31, 2004, as stated in their report which is included herein.

100 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
Devon Energy Corporation:

We have audited management's assessment, included in the accompanying Management's Annual Report on Internal Control Over

Financial Reporting that Devon Energy Corporation maintained effective internal control over ﬁnancial reporting as of December 31, 2004,
based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Devon Energy Corporation's management is responsible for maintaining effective internal control over
ﬁnancial reporting and for its assessment of the effectiveness of internal control over ﬁnancial reporting. Our responsibility is to express an
opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over ﬁnancial reporting based
on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those

standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over ﬁnancial
reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over ﬁnancial reporting,
evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such
other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over ﬁnancial reporting is a process designed to provide reasonable assurance regarding the reliability of

ﬁnancial reporting and the preparation of ﬁnancial statements for external purposes in accordance with generally accepted accounting
principles. A company's internal control over ﬁnancial reporting includes those policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly reﬂect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company's assets that could have a material effect on the ﬁnancial statements.

Because of its inherent limitations, internal control over ﬁnancial reporting may not prevent or detect misstatements. Also, projections

of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that Devon Energy Corporation maintained effective internal control over ﬁnancial

reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Devon
Energy Corporation maintained, in all material respects, effective internal control over ﬁnancial reporting as of December 31, 2004, based
on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Devon Energy Corporation and subsidiaries as of December 31, 2004 and 2003, 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, 2004, and our report dated March 4, 2005 expressed an unqualiﬁed opinion on those consolidated ﬁnancial
statements.

Oklahoma City, Oklahoma
March 4, 2005

D I S C O V E R I N G D E V O N 101

Non-GAAP Financial Measures

The United States Securities and Exchange Commission requires public companies such as Devon to reconcile Non-GAAP (GAAP

refers to generally accepted accounting principles) ﬁnancial measures to related GAAP measures.

Devon believes that using net debt, deﬁned as debt less cash, short-term investments and the debentures exchangeable into shares of
ChevronTexaco common stock, for the calculation of total capitalization provides a better measure than using debt. Management believes
that because cash and short-term investments can be used to repay indebtedness, netting cash and short-term investments against debt
provides a clearer picture of the future demands on these assets to repay debt. Furthermore, included in Devon’s indebtedness are $692
million of debentures that are exchangeable into 14.2 million shares of ChevronTexaco common stock owned outright by Devon. Since
these shares, with a market value of $745 million as of December 31, 2004, are being held by Devon exclusively to satisfy the related
indebtedness, Devon believes that netting the value of the debentures provides a clearer picture of the future demands on cash to repay debt.
This methodology is also utilized by various lenders, rating agencies and securities analysts as a measure of Devon’s indebtedness.

Reconciliation to GAAP Information

Net Debt
Total debt (GAAP)
Adjustments:

Cash and short-term investments
Debentures exchangeable into ChevronTexaco Corporation common stock
Net Debt (Non-GAAP)

Total Capitalization
Total debt
Stockholders’ equity

Total Capitalization (GAAP)

Adjusted Capitalization
Net debt
Stockholders’ equity

Adjusted Capitalization (Non-GAAP)

DECEMBER 31,

2004

2003

(IN MILLIONS)

7,964

8,918

(2,119)
(692)
5,153

7,964
13,674
21,638

5,153
13,674
18,827

(1,273)
(677)
6,968

8,918
11,056
19,974

6,968
11,056
18,024

Drill-bit capital, a non-GAAP measure, is deﬁned as costs incurred less proved acquisition costs, unproved acquisition costs resulting

from business combinations, and the net difference of accrued future asset retirement costs less actual cash retirement expenditures.
Management believes drill-bit capital is relevant because it provides additional insight into costs associated with current year drilling, facilities
and unproved acreage acquisitions related to the company’s exploration program. It should be noted that the actual costs of reserves added
through the company’s drilling program will differ, sometimes signiﬁcantly, from the direct comparison of capital spent and reserves added
in any given period due to the timing of capital expenditures and reserve bookings. This methodology is also utilized by certain securities
analysts as a measure of Devon’s performance.

Drill-bit Capital
Costs Incurred (GAAP)
Less:

Proven acquisition costs
Unproven acquisition costs resulting from business combinations
Accrued asset retirement costs
Plus: Actual retirement expenditures
Drill-bit capital (Non-GAAP)

102 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

YEAR ENDED DECEMBER 31,

2004

2003

(IN MILLIONS)

2,852

38
—
51
42
2,805

8,071

4,209
1,063
182
37
2,654

JOHN W. NICHOLS, 90, 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

Directors

DAVID M. GAVRIN, 70, joined the
board of directors in 1979 and serves as
chairman of the Compensation
Committee. Gavrin has been a private
investor since 1989 and is currently a
director and chairman of the board of
MetBank Holding Corp. From 1978 to
1988, he was a general partner of

and gas drilling fund ever registered with the Securities and
Exchange Commission. Nichols is a non-practicing Certified
Public Accountant.

Windcrest Partners, a private investment partnership in New York
City. For 14 years prior to that, he was an officer of Drexel
Burnham Lambert Inc.

J. LARRY NICHOLS, 62, is a co-
founder of Devon. He was named
chairman of the board of directors in
2000. He has been a director since 1971.
Nichols served as president from 1976
until 2003 and has served as chief
executive officer since 1980. Nichols
serves as a director of Smedvig ASA and

Baker Hughes Inc. He is a director of the Oklahoma City Branch
of the Federal Reserve Bank of Kansas City. Nichols also serves as
a director of several trade associations that are relevant to the
conduct of the company’s business. Nichols has a Bachelor of
Science degree in geology from Princeton University and a law
degree from the University of Michigan.

MICHAEL E. GELLERT, 73, joined the
board of directors in 1971 and serves as
chairman of the Nominating and
Governance Committee. 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 serves on the boards
of Humana Inc., Seacor Smit Inc., Six Flags Inc., Travelers Series
Fund Inc., Dalet Technologies and Smith Barney World Funds.

THOMAS F. FERGUSON, 68, joined
the board of directors in 1982 and serves
as 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.

PETER J. FLUOR, 57, joined the board
of directors in 2003. Fluor previously
served as a director of Ocean Energy Inc.
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 executive officer of Texas Crude Energy Inc.
He also serves on the board of Cooper Cameron Corp. and
serves as lead independent director of Fluor Corp.

JOHN A. HILL, 63, joined the board of
directors in 2000 following Devon’s merger
with Santa Fe Snyder. Hill has been with
First Reserve Corp., an oil and gas invest-
ment management company, since 1983
and is currently its vice chairman and
managing director. Prior to creating First
Reserve Corp., Hill was president and chief

executive officer of several investment banking and asset manage-
ment companies 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. and various companies controlled by First
Reserve Corp.

ROBERT L. HOWARD, 68, joined the
board of directors in 2003 and serves as
chairman of the Reserves Committee.
Howard previously served as a director of
Ocean Energy Inc. from 1996 to 2003. He
retired in 1995 from his position as vice
president of Domestic Operations,
Exploration and Production, of Shell Oil

Co. Howard is also a director of Southwestern Energy Co. and
McDermott International Inc.

D I S C O V E R I N G D E V O N

103

D I R E C T O R S & S E N I O R O F F I C E R S

WILLIAM J. JOHNSON, 70, joined
the board of directors in 1999. Johnson
previously served as a director of
PennzEnergy Co. and has been a private
consultant in 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, 56, joined
the board of directors in 1998. Kanovsky
was a co-founder of Northstar Energy
Corp., acquired by Devon in 1998, and
served on Northstar’s board of directors
from 1982 to 1998. 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 Accrete Energy Inc., ARC Resources Ltd., Bonavista
Petroleum Ltd., Pure Technologies Ltd. and TransAlta Corp.

CHARLES F. MITCHELL, M.D., 56,
joined the board of directors in 2003.
Mitchell previously 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.

J. TODD MITCHELL, 46, joined the
board of directors in 2002. Mitchell
previously served on the board of
directors of Mitchell Energy &
Development Corp. from 1993 to 2002.
He has served as president of GPM Inc.,
a family-owned investment company,
since 1998. Mitchell has also served as

president of Dolomite Resources Inc., a privately owned mineral
exploration and investments company, since 1987 and as
chairman of Rock Solid Images, a privately owned seismic data
analysis software company, since 1998.

104 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

ROBERT A. MOSBACHER JR., 53,
joined the board of directors in 1999
following Devon’s merger with
PennzEnergy Co. He has served as
president and chief executive officer of
Mosbacher Energy Co. since 1986.
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.

Senior Officers

JOHN RICHELS, 53, 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 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 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.

STEPHEN J. HADDEN, 49, was named
senior vice president, Exploration and
Production, in 2004. Hadden joined
Texaco, now ChevronTexaco, as a field
engineer in 1977 and subsequently held a
series of engineering and management
positions with increasing responsibility in
the United States. His tenure with Texaco

included assignments as assistant to the president of Texaco
Exploration Production; division manager for the Bakersfield

Producing Division; and assistant to the chairman of the board of
Texaco, where he assisted executive management with the
oversight of the company’s worldwide business in more than 140
countries. He also served as vice president of Texaco Exploration
and Production, which included responsibility for the company’s
western region, and then served as vice president of the California
Business Unit. In 2002, he became an independent consultant.
Hadden holds a bachelor’s degree in chemical engineering from
Pennsylvania State University.

BRIAN J. JENNINGS, 44, was elected
to the position of senior vice president,
Corporate Finance and Development, and
chief financial officer in 2004. He served
as senior vice president, Corporate
Finance and Development, from 2001 to
March 2004. Jennings joined Devon in
2000 as vice president of 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 started
his energy career with ARCO International Oil & Gas, a
subsidiary of Atlantic Richfield Co. Jennings received his Bachelor
of Science degree in petroleum engineering from the University of
Texas at Austin and his Master of Business Administration degree
from the University of Chicago’s Graduate School of Business.

DUKE R. LIGON, 63, was elected to
the position of senior vice president and
general counsel in 1999. Ligon had
previously 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
litigation), he has direct involvement with
Devon’s governmental affairs and its merger and acquisition activi-
ties. Prior to joining Devon, Ligon practiced energy law for 12
years and last served as a partner at 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. Departments 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.

Senior Officers

MARIAN J. MOON, 54, 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 20 years serving in various capacities,
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 as treasurer. Moon is a member of the Society of Corporate
Secretaries & Governance Professionals. She is a graduate of
Valparaiso University.

DARRYL G. SMETTE, 57, 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/BHP Petroleum (Americas)
Inc., where he last served as director of Marketing. Smette is also
an oil and gas industry instructor, approved by the University of
Texas Department 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.

D I S C O V E R I N G D E V O N

105

Glossary of Terms

Bitumen: A viscous, tar-like oil that requires
non-conventional production methods such as
mining or steam-assisted gravity drainage.

Block: Refers to a contiguous leasehold position.
In federal offshore waters, a block is typically
5,000 acres.

British thermal unit (Btu): A measure of heat
value. An Mcf of natural gas is roughly equal to
one million Btu.

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
productive. 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.

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.

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.

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.

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.

Oil sands: A complex mixture of sand, water
and clay trapping very heavy oil known as
bitumen.

Pilot program: A small-scale test project used to
assess the viability of a concept prior to commit-
ting 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 and government take, 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.

Proved reserves: Estimates of oil, gas and NGL
quantities thought to be recoverable from
known reservoirs under existing economic and
operating conditions.

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.

Gross acres: The total number of acres in which
one owns a working interest.

Royalty: The landowner’s share of the value of
minerals (oil and gas) produced on the property.

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.

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 unescalated prices.
Future production and development 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%.

106 D E V O N E N E R G Y A N N U A L R E P O R T 2 0 0 4

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 utilizes measurement and
interpretation of shear wave data. 4-C seismic
improves the resolution of seismic images below
shallow gas deposits.

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

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

C O M M O N S T O C K
T R A D I N G D A T A

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
Telephone: (405) 235-3611
Fax: (405) 552-4550

GULF, GULF COAST and INTERNATIONAL
OPERATIONS
Devon Energy Corporation
Devon Energy Tower
1200 Smith Street
Houston, TX 77002-4313
Telephone: (713) 286-5700

CANADIAN OPERATIONS
Devon Canada Corporation
2000, 400 - 3rd Avenue S.W.
Calgary, Alberta T2P 4H2
Telephone: (403) 232-7100

I N V E S T O R I N F O R M A T I O N

Information

QUARTER

HIGH

LOW

LAST

VOLUME

2003
First
Second
Third
Fourth

2004
First
Second
Third
Fourth

$ 25.19
$ 28.33
$ 26.74
$ 29.40

$ 30.56
$ 33.75
$ 37.90
$ 41.64

$ 21.23
$ 22.63
$ 23.19
$ 22.95

$ 25.88
$ 28.68
$ 31.61
$ 34.55

$ 24.11
$ 26.70
$ 24.10
$ 28.63

$ 29.08
$ 33.00
$ 35.51
$ 39.03

176,744,000
214,691,400
185,438,200
177,478,172

195,907,400
183,259,600
189,934,000
196,976,100

SHAREHOLDER ASSISTANCE
For information about transfer or exchange of
shares, dividends, address changes, account
consolidation, multiple mailings, lost certificates
and Form 1099:

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

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 Wednesday,
June 8, 2005, on the Third Floor of the
Bank One Center, 100 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 New York Stock Exchange
(symbol: DVN). There are approximately
19,000 shareholders of record.

T H E D E V O N W E B S I T E

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.

D I S C O V E R I N G D E V O N

107