Devon Energy Annual Report 2007

FY2007 Annual Report · Devon Energy

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Commitment Runs Deep

Devon Energy 2007 Annual Report

Corporate Profile
Devon is the largest U.S.-based independent oil and gas
producer. Devon’s operations are focused primarily in the
United States and Canada; however, the company also
explores for and produces oil and natural gas in select
international areas. We also own natural gas pipelines,
processing and treatment facilities in many of our producing
areas, making us one of North America’s larger processors of
natural gas liquids. Devon is included in the S&P 500 Index
and trades on the New York Stock Exchange under the ticker
symbol DVN.

Letter to Shareholders
Chairman and CEO Larry Nichols reviews
Devon’s best year as a public company.

Insight
We respond to questions concerning our
business and operating strategies.

Five-Year Highlights

Being a good neighbor
How we have improved lives in one
Canadian community.

It’s about giving back
Our employees give back to their hometowns.

Recognizing the essentials
Devon is acting to reduce carbon emissions.

Clean air and pure water
We offer examples of our commitment
to the environment.

Everyday energy
Petroleum-based products enhance our
quality of life.

Getting results
A land owner comments on his experience
with Devon.

Developing our full potential
We discuss significant projects and
opportunities for growth.

11-Year Property Data

Operating Statistics by Area

A reputation for safety
A government official praises Devon as a
safe operator.

Property Highlights

Index to Financials

Directors and Senior Officers

Glossary

Investor Information and Stock Performance

110

112

113

Commitment Runs Deep

Letter to Shareholders

Dear Fellow Shareholders: 2007 was the best
year in Devon’s 20-year history as a public
company. We increased oil and natural gas
production 12% to 224 million oil-equivalent
barrels. This production growth, coupled
with robust oil and natural gas prices, drove
earnings and cash flow to the highest levels
ever. Net earnings reached a record $3.6
billion, or $8.00 per diluted share, and cash
flow from operations climbed to $6.7 billion.

During 2007, we also executed the

largest drilling program in the company’s
history with excellent results. We drilled
2,395 successful oil and natural gas wells,
adding almost 400 million equivalent
barrels of new reserves at very attrac-
tive finding and development costs. This
drove year-end proved oil and natural gas
reserves to an all-time high of 2.5 billion
oil-equivalent barrels.

We also achieved first production in
2007 on three important long-term proj-
ects: our Jackfish thermal oil sands project,
our Merganser gas field in the deepwater
Gulf of Mexico and our Polvo oil develop-
ment in Brazil’s Campos Basin. In addition,
we sanctioned for development our first
project in the deepwater Gulf of Mexico’s
Lower Tertiary trend. Yes, Devon’s 2007
performance was outstanding on all fronts.

J. Larry Nichols

Committed to Results

Devon’s 2007 growth reflects produc-
tion increases from each of our geographic
segments: the United States, Canada and
International. In the United States, Devon
continued its reign as the undisputed leader
in North America’s flagship gas resource
play, the Barnett Shale. Our extensive expe-
rience base and technological advances are
allowing us to drill wells more quickly and to
increase per well recoveries. In 2007, only
four years after Devon pioneered horizontal
drilling in the play, we drilled our 1,000th
horizontal Barnett well. During the year, we
increased Devon’s share of Barnett produc-
tion by more than one third to 950 million
cubic feet equivalent per day. Furthermore,
we now expect to reach a production goal
for the Barnett of one billion cubic feet
of gas equivalent per day in mid-2008, 18
months ahead of schedule.

As first mover in the Barnett, we estab-
lished the best acreage position in the play,
by far. We have thousands of future drilling
locations in the best areas of the field, and
we acquired this position at a fraction of the
cost of the late-comers. As a result, Devon’s
returns in the Barnett are far superior to
that of the competition. Furthermore, we
are positioned for continued growth in the
Barnett Shale for many years to come.

The Barnett Shale is only one of several

key onshore areas in the United States.
At Carthage in east Texas, we increased
production by 19% in the fourth quarter of
2007 to 277 million cubic feet equivalent
per day. In Oklahoma, we are applying our
Barnett Shale experience to the Woodford
Shale play. In the Rocky Mountains, we con-
tinue active development programs in the
Washakie and Powder River Basin areas in
Wyoming and at Bear Paw in Montana.

Alberta’s provincial government rocked

the oil and gas industry in 2007 when it
announced plans to increase the govern-
ment’s royalty take from energy producers.
The rule changes are complex and impact
different types of oil and gas production
to varying degrees. As a result, Devon has
reallocated some capital from Alberta to
competing projects with more attractive
returns elsewhere in Canada and in the
United States. Fortunately, the economic
impact of the royalty changes on two of our
more significant areas of current investment
in Alberta, Jackfish and Lloydminster, will be
minimal.

In the fourth quarter of 2007, we com-

pleted construction of our 100%-owned
Jackfish thermal oil sands project. With
construction finished, we are injecting
steam underground and oil is flowing to the
surface. We expect production from Jack-
fish to climb gradually to a peak of 35,000
barrels per day and to continue producing
at that rate for more than 20 years. We also
expect to sanction a second 35,000 barrel
per day project, Jackfish 2, in 2008.

Southeast of Jackfish, in the Lloydmin-
ster area, we drilled 429 wells in 2007. This
enabled us to increase production by 40
percent to 33,500 equivalent barrels per
day. We expect to drill a similar number of
wells at Lloydminster in 2008.

Committed to the Future

Devon’s dependable and repeatable
development projects underpin the pro-
duction growth that we delivered in 2007
and expect to deliver in 2008. However, to
ensure sustainable growth, the pipeline of
development projects must be continually
filled. To that end, we are committed to
restocking our inventory of development
projects through high-impact exploration.
Nothing better demonstrates Devon’s
long-term commitment and the promise it
holds than our projects in the deepwater
Lower Tertiary trend in the Gulf of Mexico.
We drilled our first well in this emerging
resource in 2002. And while we do not
expect to produce our first barrel from the
play until 2010, the potential of the prize
more than justifies the wait.

Since 2002, we have made four sig-
nificant discoveries in the deepwater Lower
Tertiary. Devon’s share of these four dis-
coveries could be as much as 900 million
barrels of oil. And this is just the beginning.
As one of the first participants in the play,
Devon was able to establish an extensive
acreage position and gain considerable
experience. We have a deep inventory of

Devon increased net earnings to a record $8.00
per diluted share and cash flow to a record $6.7
billion in 2007. This enabled the company to fund
its largest-ever exploration and development
capital budget of $5.9 billion.

Lower Tertiary drilling prospects that will
enable us to continue exploring the trend
throughout the next decade.

Cascade, the first of Devon’s four
Lower Tertiary discoveries, is now entering
the development phase. We are also mov-
ing closer to development decisions on
the other three Lower Tertiary discoveries:
Jack, St. Malo and Kaskida. We conducted
appraisal drilling operations on each of
these projects in 2007 and have more wells
planned for 2008. We anticipate complet-
ing development plans within the next two
years for Jack and St. Malo.

Devon’s balanced portfolio of near-
term, predictable development projects
backed by high-impact, long-term explora-
tion uniquely positions the company for
lasting success. In a world where oil and
natural gas are increasingly scarce com-
modities, we are well positioned to help
satisfy the demand and reap the rewards.

Commitment Runs Deep

We say farewell to a member of our
senior management team this year. Marian
Moon, senior vice president of administra-
tion, is retiring after a 24-year career with
Devon. I deeply appreciate Marian’s years
of service and her significant contribution
to Devon’s success. We will miss her and
wish her the very best.

Devon could not have achieved the

growth and success we have enjoyed with-
out the commitment of our employees. The
company was recently named to FORTUNE
magazine’s list of the “100 Best Companies
to Work for.” We congratulate each and
every member of our team for their contri-
butions to creating the culture that earned
this elite recognition.

The theme of this annual report, Com-

mitment Runs Deep, reflects our culture
and the promise that Devon has made to
our stakeholders. This promise is our com-
mitment to continuous improvement and
delivering positive results. It is our commit-
ment to respect the environment and to
improve the communities in which we live
and work. Most importantly, it is our com-
mitment to treat everyone with honesty,
fairness and respect. I am extremely proud
of how Devon’s employees are delivering
on this promise. In the following pages we
will share with you some examples of the
depth of Devon’s commitment.

J. Larry Nichols
Chairman and Chief Executive Officer
March 20, 2008

8.00

6.26 6.34

6.7

6.0

5.6

5.9

4.9

4.38

4.04

4.8

3.8

3.5

2.3 2.5

Earnings per Share
($ Diluted)

Net Cash Provided by
Operating Activities
($ Billions)

Exploration and
Development Capital
($ Billions)

Insight

Management responds to investor questions

Devon plans to utilize a floating
production, storage and offloading
vessel (FPSO) to develop the
Cascade project in the Gulf of
Mexico. What are the reasons for
that decision?

There are several reasons for
selecting an FPSO for our first Lower
Tertiary development project. One is
the lack of oil pipeline infrastructure
in the vicinity of Cascade. The Cascade
prospect is in more than 8,000 feet of
water and 130 miles from shore. Shuttle
tankers will transport oil from the
Cascade FPSO to Gulf Coast refineries.
Using an FPSO with shuttle tankers
will also allow us to develop the project
more quickly than if we were to design,
construct and install more permanent
facilities.

Another advantage of an FPSO is
scalability. Initially, we plan to drill and
produce two wells at Cascade. We will
monitor and measure the performance
of those initial wells as we learn more
about the characteristics of the oil
reservoir and optimize the number of
wells necessary to fully develop the field.
This approach will allow us to proceed at
a measured pace and increase the scale
of the project as our understanding of
the reservoir increases. Additionally, by
leasing the FPSO and shuttle tankers

we will limit our capital investment in
the early stages of the project. Although
this will be the first FPSO utilized in
U.S. waters, the technology has been
extensively tested in offshore basins in
other parts of the world. Our partner in
Cascade, Petrobras, is a world leader in
the use of FPSOs.

Some exploration and production
companies have purchased drilling
rigs and entered into other non-
core businesses. Does Devon plan to
do the same?

There has been a tendency in
our industry for some competitors to
venture into ancillary businesses, such
as owning drilling rigs. This has typically
been when prices for oil field services,
such as drilling, were on the rise.
Experience tells us, however, that as the
forces of supply and demand for those
services adjust, prices come back down.
Consequently, the economic advantage
of entering a non-core business can
disappear abruptly.

Devon is principally an exploration

and production company. This means
that we search for new oil and natural
gas reserves and produce and market
those reserves. Although drilling is
necessary to our operations, it is not
a core business. We hire specialists
because that is what they do best. We
have no plans to diversify into any oil
field service businesses.

Devon has not made a major
corporate acquisition since 2003.
Why not?

Between 1998 and 2003, Devon

completed six progressively larger
transactions that totaled more than
$22 billion. Why did we stop in 2003?
Because reinvestment opportunities
within our existing property portfolio
were superior to those available through
large-scale corporate acquisitions.
That does not mean, however, that we
abandoned the acquisitions market
completely. In 2006, we acquired
properties in the Barnett Shale field at a
cost of about $2 billion. That transaction
enabled us to significantly increase our
leadership position in the Barnett Shale.

Today, the investment opportunities

we have available through drilling and
repurchasing Devon shares continue
to be better than the opportunities
available through large-scale
acquisitions. Will we ever do another
corporate acquisition? That is hard to
say because economic conditions and
opportunities constantly change. But
for now, Devon has a strong, growing
asset base, with many thousands of
potential locations available for drilling.
Acquisitions are not necessary for us to
enjoy a healthy growth profile.

Why did you decide against forming
a publicly-traded master limited
partnership?

Devon announced in July 2007 that

we planned to form a master limited
partnership (MLP) that would own a
minority interest in our marketing and
midstream business. A stated reason
for the planned transaction was to
enable the securities markets to place
an independent value on Devon’s
marketing and midstream operations.
We believed that this segment of our
business, which generated more than
$500 million of operating profit for
Devon in 2007, was not fully reflected in
the price of our common stock.

At the time we announced our
plans for an MLP, the market for yield-
driven investments was very receptive.
During the second half of 2007, world
credit markets were beset by a cascade
of bad news and the MLP market
deteriorated considerably. This led us to
withdraw Devon’s prospective offering.
Whether or not we reconsider forming
an MLP will depend largely upon
how the market for such investments
rebounds in the future.

What led to your decision to divest
your operations in Africa?

We reached the decision to
exit after evaluating the relative
risks and rewards of making further
investments in Africa versus competing
opportunities. We weighed several
factors including geopolitical risks,
fiscal terms and proximity to markets.
We also found it difficult to secure
a competitive advantage over large,
national oil companies in acquiring
the best exploration opportunities in
this part of the world. The national oil
companies, often backed by foreign
governments, can offer incentives to the
host countries that we cannot match.

Ultimately, the decision hinged
on the allocation of resources – both
capital and people. We concluded that
Devon could deploy our resources more
efficiently and effectively elsewhere.
This includes the Lower Tertiary trend
in the Gulf of Mexico, the oil sands in
Canada and exploration prospects in
Brazil and China.

With many employees in your
industry nearing retirement age,
what is Devon doing to attract and
retain talent?

Hiring and retaining a skilled
workforce is, and will continue to be,
a challenge to the energy industry as
experienced employees retire. Past
periods of low commodity prices and
underinvestment caused many to leave
oil and gas jobs and reduced the number
of college students choosing petroleum-
related careers. Devon is attempting
to reverse this situation in several
ways. One is by lending our support
to universities that train petroleum
professionals. Another is by aggressively
recruiting on college campuses and
offering attractive internship programs
to students pursuing oil and gas careers.
We are also devising compensation

and benefit programs with features
attractive to both young people entering
the workforce and to older, established
employees. Devon recently won the
attention of the national business
press by offering alternative retirement
savings plans that address the concerns
of employees at all stages of their
careers. We are also considering other
options that could entice experienced
professionals to extend their careers
as they transition into retirement. Our
goal is for Devon to be among the most
desirable employers in our industry. Our
recognition in 2008 as one of FORTUNE
magazine’s “100 Best Companies
to Work for” indicates that we are
succeeding in that pursuit.

Five-Year Highlights

YEAR ENDED DECEMBER 31,

2003

2004

2005

2006

2007

LASt YEAR (4)
CHANGE

Financial Data () (Millions, except per share data)
Total revenues
Total expenses and other income, net (2)
Earnings before income taxes

Total income tax expense

Earnings from continuing operations

Earnings from 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

Net cash provided by operating activities

Cash dividends per common share
Closing common share price

DECEMBER 31,

Total assets
Debentures exchangeable into shares of

Chevron Corporation common stock (3)

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

$
$

$
$
$
$

6,962
4,792
2,170

453
1,717

14
16

1,747
10
1,737

4.16
4.04

417
433

8,549
5,490
3,059

970
2,089

97
—

2,186
10
2,176

10,027
5,649
4,378

1,481
2,897

33
—

2,930
10
2,920

9,767
6,197
3,570

936
2,634

212
—

2,846
10
2,836

11,362
7,138
4,224

1,078
3,146

460
—

3,606
10
3,596

4.51
4.38

6.38
6.26

6.42
6.34

8.08
8.00

482
499

458
470

442
448

445
450

3,768

4,816

5,612

5,993

6,651

0.10
28.63

0.20
39.03

0.30
62.54

0.45
67.08

0.56
88.91

16%
15%
18%

15%
19%

118%
N/M

27%
—
27%

26%
26%

1%
1%

11%

24%
33%

2003

2004

2005

2006

2007

LASt YEAR
CHANGE

27,162

30,025

30,273

35,063

41,456

18%

677
7,903
11,056
293

692
6,339
13,674
772

709
5,248
14,862
1,272

727
4,841
17,442
(1,433)

641
6,283
22,006
257

(12%)
30%
26%
N/M

YEAR ENDED DECEMBER 31,

2003

2004

2005

2006

2007

Property Data ()
Proved reserves (Net of royalties)

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

Production (Net of royalties)

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

530
7,217
209
1,941

47
858
22
211

484
7,385
232
1,946

555
7,192
246
2,000

634
8,259
275
2,286

677
8,994
321
2,496

54
883
24
225

46
819
24
206

42
808
23
200

55
863
26
224

LASt YEAR
CHANGE

7%
9%
16%
9%

29%
7%
10%
12%

(1)

(2)
(3)

The years 2003 through 2007 exclude results from operations in Africa that were discontinued in 2006 and 2007. Revenues, expenses and production in 2003 include only eight and one-fourth months
attributable to the Ocean merger. All periods have been adjusted to reflect the two-for-one stock split that occurred on November 15, 2004.
Includes other income, which is netted against other expenses.
Devon owns 14.2 million shares of Chevron Corporation common stock. The majority of these shares are on deposit with an exchange agent for possible exchange for $652 million principal amount
of exchangeable debentures.
All percentage changes in this table are based on actual figures and not the rounded numbers shown.

(4)
N/M Not a meaningful number.

You can tell a lot about a company by looking at
what it values. At Devon, we invest in the long-
term prosperity of our business, our people, our
communities and the environment. We invest in
the technology that drives our industry amid the
world’s growing demand for energy.

Our commitment runs even deeper than our
financial resources. We invest our creativity, our
talent and our passion. We invest ourselves in
the promise to continually improve as an oil and
natural gas producer, to be a good neighbor and
to respect the environment.

Within this year’s annual report you will read
about projects that push the limits of innovation.
You will learn about our work to conserve water
and reduce greenhouse gas emissions, and you
will see how we give back. Throughout the pages
of our report, you will see what Devon values,
and you will understand our commitment.

Commitment Runs Deep

Being a good neighbor

The skating rink Devon helped to
build is a popular winter gathering
place for Austin Deranger and other
local children in Conklin, Alberta.

“Our new skating rink has been good for Conklin.
My boys, -year-old Erwin and -year-old Dakota, play
hockey there every chance they get. They go right after
school and stay until dark. We recently got electricity and
heat in the warm-up shack so now the kids will be able to
use it more, especially when it is so cold outside. Before
we had the rink, there was not much else for kids to do
outside except ride their all-terrain vehicles. Devon’s
skating rink project demonstrates how a company can be
a good neighbor and benefit an entire community.”

Ernie Desjarlais
Resident of Conklin, Alberta

Before Devon helped Conklin, Alberta, build an ice skating rink and
warming hut, local children in this community near Devon’s Jackfish
facilities had few places to go for fun. Today, the rink is a hub of activity
and has become a frequent location for physical education classes for a
nearby school.

Last winter, our employees held a skate drive for local children and
families. The drive exceeded our expectations, and we provided a pair of
skates for nearly everyone in the community. Several of our employees
also volunteer their time to teach children and families to skate and play
hockey.

We strive to be a good neighbor in every area where we operate.
Projects such as the ice rink and warming hut in Conklin are examples of
our commitment to enhancing the communities where we live and work.

It’s about giving back

We are dedicated to community
involvement and improving the quality
of life in the places we work. We take
pride in Devon and the company’s
accomplishments as a profitable energy
producer, and we take heart in our role
as a good neighbor. We are defined by
the character of our employees, who
give their time, money, leadership and
compassion to help others.

Community Involvement

Community involvement is a
cornerstone of Devon. We look for ways
to support our neighbors, strengthen
our schools and promote stability
through support of cultural initiatives
and civic projects.

In 2007, our employees devoted

their time and energy to help low-
income families achieve the dream
of home ownership through the
Habitat for Humanity initiative. This
nonprofit organization is dedicated
to helping people purchase simple,
affordable homes built from the
ground up through the love and labor

of volunteers. More than 100 of our
employees contributed to the effort
through a home project in Houston.
Over five days, Devon geologists,
engineers, accountants, administrators
and others worked side by side to build
a home for a family with two young
children. In north Texas, employees
weathered the summer heat to help
construct exterior and interior walls
and frame the roof of the first Habitat
for Humanity home in Wise County.
Helping those less fortunate is
a common occurrence at Devon. In
Oklahoma City, employees supported
the Regional Food Bank of Oklahoma
by donating more than 8,500 pounds
of food and $60,500 in 2007. And, in
Canada, employees loaded the Calgary
Inter-Faith Food Bank with 12,250
pounds of donated food they collected
in a mere four days.

Our employees throughout North

America play a huge role each year
in the success of the companywide
United Way campaign. Employees
in Oklahoma City, Houston, Calgary,
Bridgeport, Texas, and field offices
across North America gave a record
$3.9 million in 2007 to help the United
Way fund health and human services
organizations in our communities.

Strengthening Quality of Life

Of Devon’s many community
commitments, none is more important
and rewarding than supporting youth
and educational opportunities. Devon
has established successful partnerships
with inner-city, multicultural
elementary schools in Oklahoma
City and Houston. More than 300
employees serve as tutors and role
models, committing more than 7,500
hours to make a difference in the lives
of children. Taking time to educate the
next generation has also inspired Devon
to contribute more than $3 million in
2007 to help fund college scholarships,
supplement educational programs and
support other projects at colleges and
universities.

We also support emergency
response organizations through
a number of local commitments.
The company made a lead gift of
$200,000 to support a new police and
firefighters’ memorial in Fort Worth,
Texas. Our company also responded to
a community need at the Eaglesham
Fire Department in Alberta, Canada,
by donating a vehicle to aid its

Randy Neal, a supervisor in
Bridgeport, Texas, helps build a
Habitat for Humanity home.

Mark Twain Elementary student
Whitney Honea enjoys a day at
Devon. More than 50 Oklahoma
City employees spend an hour
each week tutoring and mentoring
students at Mark Twain.

rescue operations. Animals, too, have
played a role in how we help improve
communities. We have provided four
dogs trained for substance detection,
tracking and personal protection to
area sheriff’s departments to serve and
protect their respective communities.
Being a good neighbor is a core
Devon value. Improving the natural
environment is one of the ways Devon’s
employees demonstrate this value
in their communities. Employees in
Canada joined with students, industry
partners and community members
during the 2007 Energy in Action
program to plant trees, haul mulch and
water shrubs. Energy in Action is an
initiative focused on the environment
that brings together the petroleum
industry and communities. From mid-
September to early October, Devon
joined other member companies of the

Canadian Association of Petroleum
Producers to participate in Energy in
Action activities in 13 communities
across Canada. Devon also supports an
organization in Rio de Janeiro, Brazil,
that works with local fishing villages
to foster environmental education and
help protect the environment.

Recognizing the essentials

In the age of greenhouse gas awareness and climate change, we are
not waiting for regulatory mandates or new research. Perhaps more
important than the discussions taking place on the Capitol steps are the
steps we can take to address the matter.

Part of being a good neighbor is respecting the environment and

being aware of what we can do to reduce our impact. Because we
recognize climate change is an issue of widespread public concern, we
have developed a comprehensive program for reducing emissions of
greenhouse gases such as methane and carbon dioxide.

We believe reducing emissions is not only the right thing to do for
the environment but also benefits our business. By reducing methane
emissions, we keep more gas in the pipeline and available for sale. For
example, in 2006, our reduction program accounted for eight billion
cubic feet of natural gas. By keeping that volume of gas in the pipeline,
we increased our revenue by nearly $50 million.

“We got involved in reducing our greenhouse gas emissions several years ago
when we joined the Environmental Protection Agency’s Natural Gas STAR
program. Since then, we have been installing special equipment and taking
other steps to reduce methane and carbon dioxide emissions. It’s a program
that benefits more than the environment. We are also saving money by keeping
more gas in the pipeline, and we are creating a safer place to work. They all go
hand in hand. Reducing greenhouse gas emissions is just the result of doing the
right thing.”

Don Mayberry
Devon Production Superintendent
Artesia, New Mexico

Clean air and pure water

You may know us as one of the top energy
producers in the United States. You may
also know us as a leader in the Gulf of
Mexico’s deep water, the oil sands of
Alberta or the shale of north Texas. But
there is another side to Devon you may not
readily see in our financial statements or in
our presentations to Wall Street.

The work we do to protect the

environment, to preserve our natural
resources and to ensure the safety of
our employees is a fundamental part
of our culture. We consistently look for
new and innovative ways to reduce our
impact on the environment.

Emissions Inventory

Water Recycling

Since 1990, we have been reducing
our greenhouse gas emissions through
a growing number of new technologies
and innovations. We have spread our
efforts across the United States and
Canada, surpassing milestones and
winning recognition from industry
and government partnerships. We
reached another important stage of
our program in 2007 with development
of a monitoring system that allows us
to track methane and carbon dioxide
emissions from production facilities
companywide.

The inventory is a useful tool
in our ongoing effort to cut carbon
dioxide emissions and to keep methane
in the pipeline and available for sale.
Using this system, we can evaluate our
operations and identify opportunities
for reductions. With this information
we can determine the most effective
locations to deploy emissions reduction
technologies such as the installation of
vapor recovery units on tank batteries,
or the use of modern, low emission
valves at well sites, pipelines and
compressor stations.

In 2007, we inventoried our annual
carbon dioxide emissions from Devon’s
U.S. operations. Factored against
production, our emissions intensity
was at or below that of other large
North American oil and natural gas
producers. Through the inventory we
can document reduction in emissions
intensity, track our progress, set goals
and disclose results to stakeholders.
As concern over climate change
issues continues to build, we expect
ongoing progress and believe our
inventory gives us a solid foundation
from which to measure future progress.

Part of what we do as an
environmental steward is look for
opportunities to conserve our natural
resources. Our pioneering effort to
recycle water in north Texas is an
example of how innovation can benefit
the environment and surrounding
communities.

The Barnett Shale surrounding Fort

Worth is the fastest-growing natural
gas field in the nation, producing more
than three billion cubic feet of gas
per day from a geological formation
that extends over 5,000 square miles.
However, shale gas is an unconventional
resource requiring large amounts of
fresh water to stimulate production.

In 2005, we began a recycling
program to reclaim water used to
stimulate our natural gas wells. We use
heat to vaporize waste water recovered
from the wells, then condense the
steam into distilled water to be reused
in other well stimulation projects. Since
establishing the program, we have
recycled more than five million barrels
of water.

Each year, the volume of water
we recycle grows. Our program began
with two recycling units in 2005. Today
the recycling effort has expanded to
nine units in the Barnett. The units
operate around the clock and each one
processes more than 2,500 barrels of
water a day.

While we are excited about

pioneering water recycling in the
Barnett Shale, we are not finished. We
continue to enhance the efficiency and
economics of recycling to establish new
opportunities in other areas where we
operate.

We have recycled more than five million barrels
of water utilizing units such as this in the Barnett
Shale field in north Texas.

Everyday energy

Gasoline fuels our cars and natural gas
heats our homes, but have you ever
wondered what life would be like without
the countless products derived from oil and
natural gas? In our modern world, we have
come to enjoy and expect a certain quality
of life that is sustained by everyday things
made from these natural resources.

Think about a typical weekday.

You brush your teeth, shower, put on
makeup or shave before heading off
to work. Without petroleum-based
products, you would not have the
toothbrush, toothpaste, mouthwash,
shampoo, mascara, lipstick, shaving
foam or razor for your morning routine.
If your eyesight is poor, you could not
rely on contact lenses or eyeglasses to
sharpen your vision. You would even
miss your daily multi-vitamin.

How is petroleum made into so
many everyday products? After oil is
brought to the surface, it is refined
and broken into compounds known as
fractions. Different fractions are blended
to make a variety of raw materials used
in manufacturing. These raw materials
provide the basic building blocks for a
wide variety of items we use every day.

In the kitchen, your coffee pot,
drinking cups, egg cartons and cooking
utensils are likely made from petroleum
products. Refrigerator shelves, dish
sponges, trash bags and non-stick
pans are also derived from petroleum
products.

As you drive or ride the bus to
work, do you realize the dashboard,
upholstery, windshield wipers, brake
fluid and sun visors in the vehicle are
also derived from oil and natural gas?
Even the asphalt roads we drive on are
made from petroleum products.

When you arrive at work, you
may log on to a computer to check e-
mails, dial your voice mail and jot down
messages or daily tasks. Computers,
memory chips, telephones, ballpoint
pens and ink are made from petroleum
products. So are calculators, correction
fluid, copy machines, printer cartridges
and waste baskets. Even the building
itself – from the linoleum floors and

laminate countertops to the ceiling tiles
and roof shingles – contains a host of
petroleum-based products.

If you stop to visit a loved one at
the hospital on your way home from
work, you probably encounter countless
petroleum-based products without
notice. Even advanced medical devices
such as artificial hearts, prosthetic limbs
and hearing aids are made from oil and
natural gas products. Anesthetics used
to sedate surgery patients and cortisone
used to treat arthritis and allergies are
also made from petroleum products.
Home again at the end of the
day, families depend on baby bottles,
disposable diapers, pacifiers, teething
rings and stuffed animals when raising
their young children. Each of these is
made from petroleum products. After
school your child may attend a dance
class or participate in sports. Without
petroleum products, clothing and
equipment from ballet tights to soccer
balls, footballs, tennis rackets, diving
boards and swim goggles would not

exist as we know them today. Your
artistic child might not have oil paints
and brushes and your musician might
not have her instrument or guitar
strings.

By the end of the day you are

probably looking forward to the
weekend when you can enjoy a game of
golf, ride your bicycle or go for a long
run. Golf balls, light-weight bicycles and
the rubber soles on your sneakers are all
made from oil and natural gas products.
But for now, you crawl into bed,

cozy up with pillows and blankets
made from petroleum products and fall
asleep, only to wake up to your digital
alarm clock – also made from petroleum
products – and start all over again.

Products Made From Oil and Natural Gas

air tanks
air conditioners
airplane parts
ammonia
anesthetics
antifreeze
antihistamines
antiseptics
artificial limbs
artificial hearts
artificial turf
asphalt
aspirin
automobile parts
awnings
badminton birdies
ball point pens
balloons
bandages
baseboards
bath tubs
beach umbrellas
beach balls
bedspreads
bicycle tires
blankets
blenders
board game parts
boats
brooms
bubble gum
bug spray
bumpers
buttons
cable housings
camera bags
cameras
candles
candy oils
candy paraffin
car enamel
car battery cases
car sound insulation
car polish
carbon black
carpet sweepers
carpets
cassettes
caulking
ceiling tiles
charcoal lighters

chewing gum
child car seats
cleaning fluid
clotheslines
clothing
coffeemakers
cold cream
combs
compact discs
computer chips
computer disks
computers
cortisone
counter tops
crayons
credit cards
curtains
dashboards
denture adhesives
dentures
deodorant
detergents
dice
digital clocks
dishwashing liquid
disposable lighters
dolls
doormats
dry cleaning fluid
dyes
earphones
electric razors
electrical tape
enamel
epoxy paint
eye shadow
eyeglasses
fabric softener
fabric dye
fan belts
faucet washers
fencing
fertilizers
fiberglass
filters
fishing boots
fishing rods
fishing lures
flashlights
flavoring
flea collars

floor wax
flower pots
foam rubber
folding doors
food preservatives
food packaging
footballs
laminate counter tops
furniture polish
garment bags
gasoline
glue
glycerin
golf balls
golf bags
grease
guitar strings
hair curlers
hair permanents
hair brushes
hair dye
hair dryers
hand lotion
hearing aids
heart valves
helmets
hoses
house paint
hydraulic fluid
hydrochloric acid
hydrogen peroxide
ice buckets
ice chests
ice cube trays
ink
inner tubes
insect repellant
insecticides
insulation
jet fuel
kerosene
kitchen utensils
lacquers
latex paint
laundry baskets
life jackets
light housings
lighter fluid
linoleum
lipstick
livestock feed

loudspeakers
lubricants
luggage
lunch boxes
makeup cases
mascara
matches
mattress covers
medicines
microphones
model cars
mops
motor oil
motorcycle helmets
mouthwash
movie film
nail polish
nail polish remover
newspaper ink
nylon fabric
nylon rope
oil filters
oils
outboard motors
outlet covers
paint rollers
paint brushes
paints
pan handles
panty hose
parachutes
peat moss
percolators
perfumes
permanent-press
pet kennels
petroleum jelly
phonograph records
photo film
photographs
piano keys
picture frames
pillows
ping pong paddles
plant hormones
planters
plastic bags
plastic furniture
plastic dishes
plastic wrap
plexiglass

plumbing fixtures
plywood adhesive
polar fleece
purses
putty
rain gutters
raincoats
rayon fabric
razors
recorders
recycling bins
reflectors
refrigerants
refrigerators
resins
rollerblades
roofing
rubber gloves
rubber cement
rubbing alcohol
saccharin
sacks
safety glass
salad tongs
salad bowls
sandwich bags
satellite parts
sedatives
shampoo
shaving cream
shingles
shoe polish
shoe soles
shoelaces
shoes
shopping bags
shower doors
shower curtains
ski goggles
ski clothing
skis
slacks
slip covers
sneakers
soap dishes
soaps
soft contact lenses
solvents
sports helmets
sports pads
sports car bodies

stretch pants
strollers
styrofoam
sulfa drugs
sunglasses
sweaters
swim goggles
synthetic rubber
T-shirt transfers
tape recorders
telephones
tennis balls
tennis rackets
tent pegs
tents
textiles
tires
toasters
toilet seats
tool racks
tool boxes
toothbrushes
toothpaste
toys
transformer pads
trash bags
tubing
TV cabinets
typewriter ribbons
umbrellas
uniforms
upholstery
vacuum bottles
vaporizers
varnish
videotape
vinyl
vitamin capsules
vitamins
volleyballs
watch bands
water pipes
wheelbarrows
window frames
wind sails
windshield wipers
wire coating
yarn
zippers

SOURCE: Independent Petroleum Association of Mountain States (IPAMS)

Getting results

Devon is the largest gas producer
in Texas. In 007, we drilled 59
wells in the prolific Barnett Shale
in north Texas.

“I was born in Fort Worth and have spent my entire career
in north Texas. As a businessman, it has always been
important to look for opportunities to give back to my
community. Good business means being a good neighbor.
I saw Devon demonstrate that philosophy first hand
while working on a recent drilling project on my property.
They responded quickly and effectively when adjacent
residents expressed concern about noise and truck traffic.
Devon used ingenuity, compromise and creativity to
accommodate the residents. As a result, two wells were
successfully drilled on my property. But the best part was
that the neighbors were no longer concerned about trucks
or noise.”

Holt Hickman
Businessman and land owner
Fort Worth, Texas

Sometimes a new application of an old idea is all it takes to achieve a
modern technological breakthrough. That is what happened at Devon in
2002. The old idea was horizontal drilling, and the result was a new era
for natural gas production from shale.

Devon applied horizontal drilling technology to the Barnett Shale
following the company’s acquisition of Mitchell Energy in 2002 and in
2007 drilled its 1,000th horizontal well. Prior to its acquisition, Mitchell’s
activities in the Barnett had been confined to vertical drilling in a
relatively small area with the most favorable geological characteristics.
Following the acquisition, we began experimenting with horizontal
drilling as a way to overcome geological challenges.

The pilot program showed encouraging results. By 2004, we expanded

our horizontal drilling program beyond the core to the Barnett’s more
complex areas. Horizontal drilling was the key that opened expansion
in the Barnett, and it remains a key to future expansion into shale plays
across North America.

Developing our full potential

Success for an exploration and production
company can be measured in two important
ways: by how much oil and natural gas we
profitably produce today and tomorrow.
Devon excelled in 2007 by both measures.
On an oil-equivalent basis, we increased
annual production from continuing
operations by 12%, to 224 million barrels.
We expect to grow production further
in 2008 to between 240 million and 247
million equivalent barrels.

Devon’s realized price for oil approached $64 per
barrel in 007, driving oil and gas revenues to $9.6
billion. Our successful exploration and development
programs have allowed us to grow proved reserves
to a record .5 billion barrels.

6.98

57.39

9.6

8.2 8.1

6.8

2.3

2.0

1.9 1.9

38.64

5.5

29.12

26.13

Average Price per Barrel
of Oil
($ per Bbl)

Oil, Gas and NGL
Revenues
($ Billions)

Proved Reserves
(Billion Boe)

Our capacity to increase production

is largely dependent upon how
successfully we grow proved reserves.
Proved reserves are technical estimates
of the quantities of oil and gas still
underground that can, with reasonable
certainty, be recovered under current
economic conditions. In 2007, we added
437 million oil-equivalent barrels to our
proved reserves. That was nearly twice
the amount we produced. Most of the
reserve additions, 390 million equivalent
barrels, came from successful drilling
and positive performance revisions. We
drilled 2,440 total wells in 2007, with
a success rate of 98%. Development
projects such as the Barnett Shale and
Carthage in Texas and Lloydminster
in Canada underpinned the growth.
Exploratory areas such as the deepwater
Gulf of Mexico, Brazil and China provide
opportunities to increase reserves and
production in the future. You can read
about some of Devon’s more important
exploration and development projects on
the following pages.

Devon’s Jackfish oil sands project
in Alberta, Canada, is expected to
produce 5,000 barrels per day for
more than 0 years.

Another approach we are using in
the Barnett to increase production and
reserves is infill drilling, or spacing wells
closer together. Our first horizontal
wells in the Barnett Shale were drilled
on about 160 surface acres per well.
Next, we began drilling wells on 80
surface acres, or double the initial
density. The success of that program
led to a 40-acre pilot and we are now
testing the viability of 20 surface-acre
locations. Not all Barnett acreage
will be suitable for the higher density
spacing. With more experience we
should be able to determine what the
optimum well spacing is for all of our
Barnett Shale leases.

Today, we have about 3,200
wells producing gas from the Barnett
Shale. We hold proved reserves of
more than 4.3 trillion cubic feet of gas
equivalent, yet our engineers believe
we are recovering a fraction of the gas
in place. Horizontal and infill drilling
and innovative reservoir management
practices are enabling us to extract
more and more of the clean-burning
natural gas locked in the Barnett Shale
to meet the country’s growing energy
demands.

Accelerating Growth in the
Barnett Shale

Based on both production and
reserves, the Barnett Shale in north
Texas is Devon’s largest and most
important asset — and it is still growing.
2007 was a banner year for us in
the Barnett, as we increased annual
production by 33% to more than 300
billion cubic feet of gas equivalent.
We increased proved reserves in the
Barnett in 2007 by 19%, finding more
than three times the volume of gas we
produced. The Barnett Shale is among
the largest onshore natural gas fields in
North America, and Devon is its largest
producer.

We are growing production and
reserves in the Barnett by drilling more
wells and increasing per-well recoveries.
Devon drilled 539 wells in the Barnett
Shale in 2007, compared with 383 wells
in 2006. This increase was due, in part,
because of improved drilling efficiency.
We have cut the number of days
required to drill a typical horizontal
Barnett well by half in just the past
three years. Based on fourth-quarter
results, we increased per well recoveries
from new wells in the Barnett by about
15% in 2007. Almost all of the Barnett
wells we drilled in 2007 were horizontal
wells. Not only are horizontal wells
more efficient than vertical wells, they
also cause less surface impact because
fewer drilling locations are required.

Full Steam Ahead at Jackfish

In 2007, we started injecting
steam at Devon’s 100%-owned Jackfish
oil sands project in eastern Alberta,
Canada. Jackfish has been under
construction since 2005 and utilizes
the steam-assisted gravity drainage,
or SAGD, process. Softened by steam,
heavy oil is now flowing to the surface
through wells drilled to a depth of
about 1,300 feet. That oil is processed
in surface facilities and blended with
diluents to make it flow more easily.
The blended oil is then transported on
Devon’s 50%-owned Access Pipeline for
marketing. Production is expected to
ramp up gradually to a peak of 35,000
barrels per day, which is the design
capacity of the Jackfish facilities.

We anticipate receiving regulatory
approval in 2008 for Jackfish 2, another
35,000 barrel per day SAGD project
located on adjoining leases. Jackfish and
Jackfish 2 are each expected to recover
about 300 million barrels of oil over
their more than 20-year productive
lives. Devon is the first U.S.-based
independent to operate a thermal oil
sands project in Canada.

Lloydminster Oil Volumes Climbing
In east central Alberta and west

central Saskatchewan, Canada, Devon
holds more than two million net acres
in the Lloydminster area. Production at
Lloydminster is from shallow reservoirs
between 1,300 and 2,000 feet deep.
Lloydminster oil is heavy, but can be
brought to the surface without the
steam injection process required at
Jackfish.

At Lloydminster, we are developing

Devon’s acreage in the Manatokan,
Iron River and End Lake fields. We
drilled 429 wells in the Lloydminster
area in 2007 with excellent results. We
increased 2007 average production
to 33,500 equivalent barrels per day,
40% more than in 2006. We plan to
drill another 475 wells at Lloydminster
in 2008. Because the wells are shallow
and relatively inexpensive to drill,
finding and development costs are very
attractive.

Exploring the Deep

Although development
projects such as the Barnett Shale
and Lloydminster are delivering
impressive growth, we believe long-
term, sustainable growth requires
a significant commitment to high-
impact, long-cycle-time exploration. In
2008, we will invest about $1 billion in
exploration projects that will not deliver
reserves or production for several years,
but can provide the seeds for future
growth.

Early this decade, we determined

that the deepwater Gulf of Mexico
would be a focus area for our
exploration program. We had an
experienced team of deepwater
explorationists, many of whom had
joined Devon through previous
acquisitions. We also had an extensive
seismic library and deepwater acreage
inventory. We further increased our
deepwater acreage position through
federal lease sales and joint ventures
with other operators. Today, Devon’s
deepwater lease inventory is among the
largest in the Gulf of Mexico.

Our deepwater exploration
commitment led to early and notable
success with discoveries in both
Miocene and Lower Tertiary reservoirs.
In the Miocene trend we made
discoveries at Sturgis (25% working
interest) in 2003 and Mission Deep
(50% working interest) in 2006. We are
now drilling a Miocene exploratory well
at Sturgis North (25% working interest)
and plan to drill an appraisal well at
Mission Deep later in 2008.

In 2002, we made our first
discovery in the Lower Tertiary trend.
Lower Tertiary geologic formations are
older and deeper than the Miocene-
aged rocks. Devon has to date
participated in four significant Lower
Tertiary discoveries with combined
estimated net resources of up to 900
million oil-equivalent barrels. We have
also built an inventory of about 20
untested exploratory prospects with
combined unrisked resource potential
of up to five billion oil-equivalent
barrels. This is double Devon’s current
proved reserve base of about 2.5 billion
equivalent barrels.

Our offshore employees travel to and from
the Ocean Endeavor aboard helicopters. The
drilling rig is under a long-term contract to
Devon in the Gulf of Mexico.

Of our four discoveries, Cascade

To provide greater flexibility in

is the first to be sanctioned for
development. St. Malo (22.5% working
interest) and Jack (25% working
interest), discovered in 2003 and 2004
respectively, may be sanctioned in
2009 for development. A successful
production test of the Jack No. 2 well in
2006 brought worldwide attention to
the Lower Tertiary trend and to Devon’s
stake in the play. Additional appraisal
drilling and facilities design engineering
on both St. Malo and Jack are planned
for 2008. Should St. Malo and Jack be
sanctioned in 2009, first production
could occur as early as 2013. Additional
appraisal activity is also planned
in 2008 for Kaskida (20% working
interest), a 2006 discovery.

accomplishing our deepwater drilling
plans, we have entered into long-term
contracts for two fifth-generation
offshore rigs. We took delivery of the
Ocean Endeavor, the first of the two
rigs, in 2007. We expect to take delivery
of the second rig, the West Sirius, in
mid-2008. These rigs are capable of
drilling in 10,000 feet of water and
to depths greater than 30,000 feet.
We will use the rigs for exploratory,
appraisal and development wells. The
Ocean Endeavor is now drilling the
Jack No. 3 appraisal well before moving
to drill the initial producing wells at
Cascade. We plan to drill a Devon-
operated exploratory well with the West
Sirius after it arrives in U.S. waters.

Cascade Sanctioned for Development
Cascade was the first of Devon’s
four significant discoveries in the Lower
Tertiary trend of the Gulf of Mexico.
We drilled the discovery well in 2002
and followed up with two successful
appraisal wells in 2005. Devon and
Petrobras, the Brazilian national oil
company, are equal partners in the
23,000-acre Cascade unit. In 2007,
the partners sanctioned the project for
commercial development.

We also hold interests in nine
offshore leases in Brazil, encompassing
nearly 800,000 net acres. Seven of
the lease blocks are in the prolific
Campos Basin, and we are partners with
Petrobras, Brazil’s national oil company,
in four of those blocks. In 2008, we plan
to drill a high-potential exploratory well
on Block BM-C-30. In early 2009, Devon
will take delivery under a long-term
contract of a deepwater drill ship in
Brazil. We plan to drill seven exploratory
wells with the drill ship over a two-year
period.

China is another country where

Devon has established offshore
production. Our Panyu field is located
in the Pearl River Mouth Basin in the
South China Sea. Devon and its partners
began producing oil at Panyu in 2003,
and to date Devon’s share of the
production has been about 22 million
barrels. We have a 24.5% working
interest in the project, which is operated
by the Chinese National Offshore Oil
Company, known as CNOOC.

In the first quarter of 2008,
Devon began drilling an exploratory
well on Block 42/05, also in the South
China Sea, but in deeper water than
Panyu. The BY 6-1-1 well is in 3,200
feet of water and is on trend with a
large natural gas discovery made by
another operator in 2006. We have also
identified other exploratory prospects
on Block 42/05 that we plan to test in
the future.

In addition to Block 42/05, Devon

also holds Blocks 53/30 and 64/18 in
the South China Sea and Block 11/34 in
the Yellow Sea. During the exploration
phase, we have 100% working interests
in each exploratory block. CNOOC has
the option to participate with a 51%
working interest in any discoveries.
We believe these lease blocks could
hold more than one billion barrels of
combined net resource potential for
Devon.

-Year Property Data ()

Reserves (Net of royalties)
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, Gas and NGLs (MMBoe)

10% Present Value Before Income Taxes (In millions) (2) $

Production (Net of royalties)
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, Gas and NGLs (MMBoe)

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

Unit Production and Operating Expense (per Boe)

$
$
$
$

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

Growth Rate Growth Rate

219
1,403
24
477
2,100

29
180
3
62

17.03
2.04
12.61
14.51

166
1,440
21
427
1,375

20
189
3
55

12.28
1.78
8.08
11.09

20,944

20,950

32,350

22,146

439

2,785

958

5,316

295

17.78

2.09

13.28

14.22

406

3,045

963

17,075

417

113

24.99

3.53

20.87

22.38

527

5,024

108

1,472

6,687

489

126

21.41

3.84

16.99

22.19

444

5,836

192

1,609

15,307

761

188

21.71

2.80

14.05

17.61

530

7,217

209

1,941

858

211

26.13

4.52

18.63

26.04

484

7,385

232

1,946

883

225

29.12

5.34

23.06

30.38

555

7,192

246

2,000

819

206

38.64

7.03

29.05

39.89

634

8,259

275

2,286

808

200

57.39

6.08

32.10

40.38

677

8,994

321

2,496

32,852

863

224

63.98

5.99

37.76

42.96

4.63

4.29

4.15

4.81

5.29

4.71

5.79

6.38

7.65

8.81

9.68

5-Year

Compound

10-Year

Compound

11%

17%

24%

16%

22%

20%

16%

12%

20%

29%

18%

32%

17%

25%

14%

11%

12%

11%

Cascade is located in the Walker
Ridge lease area under about 8,000 feet
of water. We plan to develop the project
with a floating production, storage and
offloading vessel, or FPSO. Although
FPSOs are deployed in many oceans
around the world, Cascade is expected
to be the first project in the Gulf of
Mexico to use this production system.
In 2007, the Cascade partners awarded
contracts for the FPSO and for two
shuttle tankers that will transport oil to
the coast.

We expect to begin drilling the first
of two initial producing wells at Cascade
later this year, with production planned
to commence in 2010. Reservoir data
gathered from these first two wells will
help determine the optimum facilities
size and number of producing wells
required to fully develop Cascade’s
potential. This phased approach will
allow us to develop the project in a
prudent and cost-effective way.

International Exploration Looks to
Brazil and China

Devon is predominately a North

American company. About 95% of
our proved reserves, excluding the
properties in Africa that we are
divesting, are in the United States and
Canada. Although currently focused in
North America, we are excited about
our prospects in Brazil and China. These
are countries with stable political, fiscal
and regulatory environments and where
we have alliances with experienced and
capable partners.

Devon established a foothold in
Brazil with our 2004 Polvo discovery in
the offshore Campos Basin. We began
producing oil at Polvo in the second
half of 2007 and expect to drill a total
of 10 producing wells and three water
injection wells. The Polvo facilities,
which include a fixed drilling and
producing platform and an FPSO, are
sized to produce up to 50,000 barrels of
oil per day. Devon operates the project
with a 60% working interest.

Operating Statistics by Area ()

Producing Wells at Year-End

8,525

7,102

6,059

4,019

682

26,387

7,975

449

34,811

Permian

Mid-
Continent

Rocky
Mountains

Gulf
Coast

U.S.
Offshore

total
U.S.

Canada

International

total
Company

2007 Production (Net of royalties)
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, Gas and NGLs (MMBoe)

Average Prices
Oil price (per Bbl)
Gas price (per Mcf)
NGLs price (per Bbl)
Oil, Gas and NGLs (per Boe)

Year-End Reserves (Net of royalties)
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Oil, Gas and NGLs (MMBoe)

7
34
3
15

$
$
$
$

67.87
6.02
34.00
50.03

90
248
26
156

1
292
13
62

68.22
5.68
35.61
34.89

6
3,972
192
860

1
100
1
19

62.02
4.54
19.35
30.15

20
1,191
11
230

2
132
4
28

70.28
6.51
40.60
41.18

15
1,354
52
293

8
77
1
22

71.95
7.17
36.78
53.30

39
378
1
103

19
635
22
146

69.23
5.89
36.11
39.87

170
7,143
282
1,642

16
227
4
58

49.80
6.24
46.07
41.51

388
1,844
39
734

20
1
—
20

70.60
6.22
—
70.11

119
7
—
120

55
863
26
224

63.98
5.99
37.76
42.96

677
8,994
321
2,496

Year-End Present Value of Reserves (In millions) (2)
Before income tax
After income tax

$
$

3,473

8,485

2,541

3,429

3,136

21,064
14,679

7,986
5,962

3,802
2,830

32,852
23,471

Year-End Leasehold (Net acres in thousands)
Developed
Undeveloped

Wells Drilled During 2007

Capital Costs Incurred (In millions) (3)

2007 Actual
2008 Forecast

302
447

155

826
533

792

549
1,378

480

508
539

224

362
2,247

2,547
5,144

2,200
5,911

54
8,631

4,801
19,686

1,662

748

2,440

214

$
1,955
$ 225-245 1,895-1,975

411
380-405

878

812
865-915 980-1,050

4,270

1,365
4,345-4,590 1,305-1,365

466

6,101
450-490 6,100-6,445

(1) Excludes results from discontinued operations.
(2) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs, discounted at 10% in accordance with SFAS No. 69,
Disclosures about Oil and Gas Producing Activities. 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 pre-tax measure in similar ways.
(3) 2007 actual costs incurred and 2008 forecasted capital costs include exploration and production expenditures, capitalized general and administrative costs, capitalized interest costs and asset retirement costs.

10% Present Value Before Income Taxes (In millions) (2) $

2,100

-Year Property Data ()

Reserves (Net of royalties)

Oil (MMBbls)

Gas (Bcf)

NGLs (MMBbls)

Oil, Gas and NGLs (MMBoe)

Production (Net of royalties)

Oil (MMBbls)

Gas (Bcf)

NGLs (MMBbls)

Oil, Gas and NGLs (MMBoe)

Average Prices

Oil (per Bbl)

Gas (per Mcf)

NGLs (per Bbl)

Oil, Gas and NGLs (per Boe)

219

1,403

477

180

17.03

2.04

12.61

14.51

166

1,440

427

1,375

189

12.28

1.78

8.08

11.09

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

439
2,785
55
958
5,316

25
295
5
79

17.78
2.09
13.28
14.22

406
3,045
50
963
17,075

37
417
7
113

24.99
3.53
20.87
22.38

527
5,024
108
1,472
6,687

36
489
8
126

21.41
3.84
16.99
22.19

444
5,836
192
1,609
15,307

42
761
19
188

21.71
2.80
14.05
17.61

530
7,217
209
1,941
20,944

47
858
22
211

26.13
4.52
18.63
26.04

484
7,385
232
1,946
20,950

54
883
24
225

29.12
5.34
23.06
30.38

555
7,192
246
2,000
32,350

46
819
24
206

38.64
7.03
29.05
39.89

634
8,259
275
2,286
22,146

42
808
23
200

57.39
6.08
32.10
40.38

677
8,994
321
2,496
32,852

55
863
26
224

63.98
5.99
37.76
42.96

Unit Production and Operating Expense (per Boe)

4.63

4.29

4.15

4.81

5.29

4.71

5.79

6.38

7.65

8.81

9.68

10-Year
5-Year
Compound
Compound
Growth Rate Growth Rate

9%
9%
11%
9%
17%

6%
3%
6%
4%

24%
16%
22%
20%

16%

12%
20%
29%
18%
32%

7%
17%
25%
14%

14%
11%
12%
11%

(1) The years 1997 through 2002 exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002. The years 2003 through 2007 exclude results from operations in
Africa that were discontinued in 2006 and 2007. 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) Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs, discounted at 10% in accordance with SFAS No. 69,
Disclosures about Oil and Gas Producing Activities. 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

A reputation for safety

“At the MMS, we routinely meet with companies throughout the year to discuss
operational issues related to safe and clean operations. The MMS District
SAFE Award recognizes exemplary performance. The honor represents a high
standard for companies to achieve and sets clear expectations for safety and
environmental stewardship. To qualify, operators must perform head and
shoulders above other companies in their safety and environmental record.
Companies that have received the recognition on repeated occasions, such as
Devon, consistently demonstrate a commitment to high standards by operating
in ways that are safe, clean and incident free.”

Elliott Smith
District Manager, Minerals Management Service,
Lafayette District

This is a look at the
workings of the Ocean
Endeavor, a latest-
generation deepwater
drilling rig.

Although we have more than 5,000 employees, we enjoy the same type
of family atmosphere that existed when Devon was much smaller. This
atmosphere encourages employees and contractors to work together to
ensure safety in everything they do.

We use peer reviews, collaboration and positive reinforcement to promote

safety from our drilling sites and our gas processing plants to our file rooms.

The Safe Actions for Everyone (SAFE) program promotes mutual
cooperation. Employees observe colleagues’ safety habits, offer positive
feedback and help nurture awareness.

Our SAFE program originated among field employees in 2004. As a
result, we have seen even lower incident rates, and we are excited about
the program’s future. Employees and contractors are already sharing
responsibility for each other’s safety, and we believe that will continue to
foster a safe workforce in the years to come.

Property Highlights

PERMIAN

A / Southeast New Mexico

MID-CONTINENT

A / Woodford Shale

Profile
• 75% average working interest in 548,000 acres.
• Key fields include Ingle Wells, Catclaw Draw,
Potato Basin, Red Lake, Gaucho, and Outland.
• Produces oil and gas from multiple formations at

1,500’ to 16,500’.

• 44.0 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 22 gas wells.
• Drilled and completed 54 oil wells.
• Recompleted 69 wells.
2008 Plans
• Drill 29 gas wells.
• Drill 46 oil wells.
• Recomplete 35 wells.

B / West Texas

Profile
• 40% average working interest in 1.1 million acres.
• Key fields include Wasson, Reeves and Anton-Irish
to the north; Ozona, Keystone/Kermit, McKnight
and Waddell to the south.

• Produces oil and gas from multiple formations at

2,500’ to 18,000’.

• 112.3 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 3 gas wells.
• Drilled and completed 25 oil wells.
• Recompleted 54 wells.
• Reactivated 22 wells.
2008 Plans
• Drill 2 gas wells.
• Drill 35 oil wells.
• Recomplete 53 wells.
• Reactivate 22 wells.
•
Reeves Unit.

Initiate enhanced oil recovery with CO2 at

Profile
• 54,000 net acres in the Arkoma Basin in eastern
Oklahoma.
• Operated working interests range from 40% to

100%.

• Unconventional natural gas play.
• Produces gas from the Woodford Shale formation

at 6,000’ to 8,000’.

• 26.6 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 89 horizontal wells (39

operated).

• Drilling focused on acreage evaluation and holding

leases by establishing production.
• Finalized acquisition of 3-D seismic.
• Divested non-core acreage.
2008 Plans
• Drill 109 horizontal wells (57 operated).
• Reprocess and merge 3-D seismic data.
• Expand gas gathering system capacity.
• Complete construction of 200 million cubic feet

per day gas plant.

B / Barnett Shale

Profile
• 727,000 net acres in the Forth Worth Basin of

north Texas.

• > 90% average working interest.
•
Includes >3,200 producing wells.
• Produces gas from the Barnett Shale formation at

6,500’ to 9,200’.

• Largest producer in the state’s largest natural gas
field.
• 724.1 million barrels of oil-equivalent reserves at

12/31/07.

Increased 2007 net production 33% over 2006.

2007 Activity
• Drilled and completed 539 wells.
•
• Continued 80 surface acre infill program.
• Began 40 surface acre infill pilot.
• Continued to improve drilling efficiencies with

new generation rigs.
• Acquired 3-D seismic.
2008 Plans
• Drill 500 – 600 wells.
• Continue to develop viable areas with 40 surface

acre infill program.
Initiate 20 surface acre infill pilot in selected areas.

•
• Re-fracture selected horizontal wells.
• Evaluate western acreage for future expansion.
• Acquire additional 3-D seismic and acreage.
• Continue to expand gas gathering system and

reduce line pressure.

• Complete construction of 100 million cubic feet

per day gas plant.

C
D

ROCky MOuNTAINS

A / Bear Paw

Profile
• 814,000 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’.

• 18.6 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 55 wells.
• Recompleted 41 wells.
• Acquired 52 square miles of 3-D seismic.
• Expanded gas gathering system capacity.

texasOklahOmanew mexicoKansasColoradotexasArkAnsAsOklahOmaGulf of MexicoLouisiananew mexicoKansasColoradoArizonANebraskaUTAHIDAHOWyomingMontanaSouthDakotaNorthDakota

2008 Plans
• Drill 50 wells.
• Continue workover and recompletion program.
• Add compression and perform other gas gathering

system improvements.

• Acquire additional 3-D seismic.

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 formations at 300’ to 2,000’.
• 27.5 million barrels of oil-equivalent reserves at

Initiated full scale development at West Pine Tree

12/31/07.
2007 Activity
• Drilled 193 coalbed natural gas wells.
•
Unit.
• Continued development drilling at Juniper Draw.
2008 Plans
• Drill 118 coalbed natural gas wells.
• Continue development and initiate first gas sales at
West Pine Tree.
• Complete development drilling at Juniper Draw.

C / Wind River Basin

Profile
• 96% working interest in 24,600 acres in central
Wyoming.
• Key fields include Beaver Creek and Riverton
Dome.
• Produces oil and gas from multiple formations at

3,000’ to 12,000’.

• 24.8 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
•

Initiated construction on Madison CO2 enhanced
oil recovery project at Beaver Creek.

• Drilled 6 Madison formation wells.
• Recompleted 7 injection wells.
Installed CO2 pipeline, flowlines and injection lines.
•
• Completed final wells for 12-well coalbed natural

gas pilot at Riverton Dome.

2008 Plans
• Drill final 6 wells for Madison CO2 project.
•

Initiate CO2 injection in Madison enhanced oil
recovery project at Beaver Creek.

• Drill 5 well coalbed natural gas pilot at Beaver Creek.

D / Washakie

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

southern Wyoming.

• Produces gas from multiple formations at 6,800’

to 10,300’.

• 111.1 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 161 wells.
•

Improved drilling efficiencies with new generation
rigs.
Installed 63 plunger lifts.
Installed compression and performed other gas
gathering system improvements.

•
•

• Continued implementation of automated

production control system.

2008 Plans
• Drill 112 total wells, including first operated

horizontal well.
Install 100 plunger lifts.

•
• Add compression and perform other gas gathering

system upgrades.

• Continue implementation of automated production

control system.

E / NEBu/32-9 units

B / Carthage Area

Profile
• 25% average working interest in 54,000 acres in
the San Juan Basin of northwestern New Mexico.
• Coalbed natural gas development began in the late

1980s and early 1990s.
Includes 304 coalbed gas wells, 302 conventional

•
wells, gas and water gathering systems and an

automated production control system.

• Produces primarily coalbed natural gas from the

Fruitland Coal formation at 3,500’.

• 16.5 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 4 coalbed gas wells.
• Drilled and completed 20 conventional gas wells.
• Recompleted 5 conventional wells.
• Completed 271-well workover program.
2008 Plans
• Drill 4 coalbed gas wells.
• Drill 17 conventional gas wells.
• Recomplete 8 conventional wells.
• Perform 270-well workover program.

GuLF COAST

A / Groesbeck Area

Profile
• 72% average working interest in 285,000 acres in

eastcentral Texas.

• Key fields include Personville, Nan-Su-Gail, Dew,
Oaks and Bald Prairie.
• Produces primarily gas from the Travis Peak,
Cotton Valley Sand, Bossier and Cotton Valley Lime

formations at 6,000’ to 13,000’.
Includes 680 producing wells.

•
• 48.8 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 17 vertical wells.
• Drilled and completed 4 horizontal wells.
• Recompleted 6 wells.
• Acquired 3-D seismic.
2008 Plans
• Drill 6 vertical wells.
• Drill 11 horizontal wells.
• Recomplete 15 wells.
• Acquire 3-D seismic.
• Expand gas gathering system capacity.

Profile
• 85% average working interest in 213,000 acres in

east Texas.

• Key fields include Carthage, Bethany, Waskom,

Stockman and Appleby.

• Produces primarily gas from the Pettit, Travis Peak
and Cotton Valley formations at 5,700’ to 9,600’.
Includes 1,666 producing wells.

•
• 193.1 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 138 vertical wells, including

31 infill wells.

• Drilled and completed 13 horizontal wells.
• Recompleted 50 wells.
• Acquired additional acreage.
2008 Plans
• Drill 99 vertical wells, including 30 infill wells.
• Drill 27 horizontal wells.
• Recomplete 32 wells.
• Acquire additional seismic and acreage.
• Expand gas gathering system capacity.

C / North Louisiana Area

Profile
• 50% average working interest in 667,000 acres in

north Louisiana.

• Own mineral interests in 139,000 net acres on
trend with lower Cotton Valley/Bossier play.
• Produces from the Hosston, lower Cotton Valley
and Bossier formations at 7,000’ to 17,000’.
• 16.7 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 5 infill wells at Ruston.
•
2008 Plans
• Drill 17 wells.
• Complete 3 field studies and identify additional

Initiated 3 field studies to evaluate future potential.

drilling locations.

D / South Texas/South Louisiana

Profile
• 66% average working interest in 575,000 acres.
• Key areas include Matagorda, Zapata, Agua Dulce/
N. Brayton, Duval/Hagist, Houston, Central Texas,
Coastal Frio and the Patterson Field in Louisiana.
• Produces oil and gas from the Frio/Vicksburg,
Yegua, Wilcox and Woodbine trends at 1,500’ to

15,000’.

• 34.4 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 41 wells.
• Drilled 1 successful exploratory well in Matagorda

area.

Initiated 3-D seismic acquisition in Brazoria area.

• Recompleted 65 wells.
•
2008 Plans
• Drill 48 wells.
• Drill 2 exploratory wells in south Louisiana.
• Recomplete 40 wells.
• Continue 3-D seismic acquisition in Brazoria area.

texasGulf of MexicoLouisianaMS

GuLF – ShELF

Shelf Producing Properties

Profile
•

Includes 32 blocks located offshore Texas,
Louisiana, and Alabama.

• Working interests range from 13% to 100%.
• Produces oil and gas from various formations in
water depths up to 600’.
• Mature producing area with opportunities for

exploration.

• 45.3 million barrels of oil-equivalent reserves at

12/31/07.

2007 Activity
• Drilled 7 wells in Eugene Island area.
• Drilled 1 well in Brazos area.
• Drilled 1 well in Mobile area.
• Recompleted 10 wells.
2008 Plans
• Drill 2 wells in Main Pass area.
• Drill 3 wells in Eugene Island area.
• Recomplete 25 wells.

h
k

G F

I
E

GuLF – DEEPWATER

A / Nansen

Includes 3 blocks in central East Breaks area.

Profile
•
• 50% working interest.
• Located offshore Texas in 3,500’ of water.
• Produces oil and gas from sands at 9,000’ to

14,000’.

• Utilizes the world’s first open-hull truss spar.
• 32.5 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Recompleted 2 wells.
2008 Plans
• Drill 2 development wells.
• Recomplete 2 wells.

B / Magnolia

Profile
• 25% working interest in Garden Banks 783 and

784.

• Located offshore Louisiana in 4,700’ of water.
• 1999 discovery.
• Produces oil and gas from sands at 12,000’ to

17,000’.

• Utilizes the world’s deepest tension-leg platform.
• 12.3 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Recompleted 2 wells.
2008 Plans
• Drill 2 sidetrack wells.
• Recomplete 2 wells.
• Evaluate potential for additional drilling.

Shelf Exploration Prospects

Profile
A / Sunfish
• West Cameron 291.
• Located offshore Louisiana in 50’ of water.
• Target formation: Lower Miocene sands at 15,900’.
• Expected working interest: 75%.
B / Dampier
• Ship Shoal 104.
• Located offshore Louisiana in 30’ of water.
• Target formation: Upper Miocene sands at 16,600’.
• Working interest: 50%.
C / Flying Squirrel
• Mobile 830.
• Located offshore Alabama in 50’ of water.
• Target formation: Norphlet sands at 22,000’.
• Expected working interest: 75%.
2007 Activity
• Finalized geophysical analyses and drilling contracts.
• Secured farmin agreement at Dampier.
2008 Plans
• Secure farmout agreements with industry partners

at Sunfish and Flying Squirrel.

• Drill exploratory test wells.

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.
• 3.7 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Produced and monitored.
2008 Plans
• Recomplete 2 wells.
• Evaluate potential for additional drilling.

D / Merganser (Independence hub)

Profile
• 50% working interest in Atwater Valley 37.
• Located offshore Louisiana in 8,100’ of water.
• 2001 discovery.
• Produces gas from sands at 19,000’ to 20,000’.
• Cooperative development of 10 nearby industry
discoveries utilizing subsea tie-backs to a central
production hub.

• 6.8 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Commenced production from 2 wells.
2008 Plans
• Produce and monitor.

Gulf of MexicotexasLouisianaMSALtexasLouisianaGulf of Mexico

Lower Tertiary Discoveries

Miocene Discoveries

Profile
E / Cascade
• 50% 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’.

Profile
I / Mission Deep
• 50% working interest in Green Canyon 955.
• Located offshore Louisiana in 7,300’ of water.
• Target formation: Miocene sands.
• Discovery well drilled in 2006 encountered > 250’

• Discovery well drilled in 2002 encountered > 450’

of net oil pay.

F / St. Malo
• 22.5% working interest in Walker Ridge 678.
• Located offshore Louisiana in 6,900’ of water.
• Target formation: Lower Tertiary sands at 26,000’

to 29,000’.

• Discovery well drilled in 2003 encountered > 450’

of net oil pay.

G / Jack
• 25% working interest in Walker Ridge 759.
• Located offshore Louisiana in 7,000’ of water.
• Target formation: Lower Tertiary sands.
• Discovery well drilled in 2004 encountered > 350’

of net oil pay.

h / kaskida
• 20% working interest in Keathley Canyon 292.
• Located offshore Louisiana in 5,900’ of water.
• Target formation: Lower Tertiary sands.
• Discovery well drilled in 2006 encountered

approximately 800’ of net hydrocarbon bearing
sands.

• First Lower Tertiary discovery in Keathley Canyon

area.

2007 Activity
• Sanctioned phase 1 development at Cascade.
• Submitted Cascade operating and development

plans to MMS.

• Awarded Cascade development contracts,

•

including FPSO and shuttle tankers.
Initiated drilling 2nd and 3rd appraisal wells at
St. Malo.
•
Initiated drilling 2nd appraisal well at Jack.
• Evaluated development options and facilities

designs for Jack and St. Malo.

• Planned for next appraisal operation at Kaskida.
• Acquired 25 additional Lower Tertiary blocks

through federal lease sales.

2008 Plans
• Drill first of 2 producing wells at Cascade.
• Finish drilling 2nd and 3rd appraisal wells at

St. Malo.

• Finish drilling 2nd appraisal well at Jack.
• Drill appraisal well at Kaskida.
• Continue evaluating development options and
advance engineering work at Jack, St. Malo and

Kaskida.
• Finalize gas export pipeline arrangements at
Cascade.

J /Sturgis
• 25% working interest in Atwater Valley 183.
• Located offshore Louisiana in 3,700’ of water.
• Target formation: Miocene sands.
• Discovery well drilled in 2003 encountered > 100’

of net oil pay.

• Sturgis North exploratory prospect located on
Atwater Valley 182.
2007 Activity
• Completed drilling sidetrack appraisal well at
Mission Deep.
2008 Plans
• Drill Mission Deep appraisal well.
• Evaluate Mission Deep development options.
• Drill exploratory well on Sturgis North prospect.

Deepwater Exploration Prospects

Profile
k / Bass
• Keathley Canyon 596.
• Located offshore Louisiana in 6,450’ of water.
• Target formation: Lower Tertiary sands.
Additional Lower Tertiary Prospect # 1
• Located in Walker Ridge area.
• Located offshore Louisiana in 7,000’ of water.
• Target formation: Lower Tertiary sands.
Additional Miocene Prospect #1
• Located in Mississippi Canyon area.
• Located offshore Louisiana in 3,300’ of water.
• Target formation: Miocene sands.
2007 Activity
•
• Conducted technical evaluations and initiated

Initiated drilling 2 exploratory wells.

drilling contracts.

• Commenced long-term contract with delivery of
Ocean Endeavor deepwater drilling rig.
2008 Plans
• Finish drilling 2 exploratory wells initiated in 2007.
• Finalize technical evaluations and contracts.
• Drill exploratory test wells.
• Commence long-term contract with delivery of
West Sirius deepwater drilling rig.

A
B
C

E
D

CANADA

A / Northeast British Columbia

Profile
• 72% average working interest in 1.7 million acres
in northwestern Alberta and northeastern British

Columbia.
• Key areas include Hamburg/Chinchaga, Ring
Border, Peggo, Eagle, Monias, West Jedney and
Wargen.
• Primarily winter-only drilling.
• Produces oil and gas from multiple formations
including liquid-rich gas from the Halfway and

Baldonnel at 2,600’ to 5,000’.
• 58.2 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled 64 wells, including:
23 at Wargen.
16 at Ring Border.
11 at Hamburg/Chinchaga.
7 at West Jedney.
2008 Plans
• Drill 37 total wells, including:
9 at Hamburg/Chinchaga.
8 at Wargen.
7 at West Jedney.
3 at Monias.
3 at Eagle.

B / Peace River Arch

Profile
• 70% average working interest in 708,000 acres in
western Alberta.
• Key areas include Belloy, Cecil, Dunvegan, Knopcik,
Valhalla and Tangent.
• Produces liquids-rich gas and light gravity oil from
multiple formations at 3,000’ to 8,000’.
• 74.2 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled 60 wells, including:
16 at Dunvegan.
13 at Cecil.
6 at Belloy.
5 at Knopcik.
2008 Plans
• Drill 65 total wells, including:
19 at Dunvegan.
10 at Cecil.
5 at Valhalla.
4 at Knopcik.
3 at Tangent.

SaSkatchewanAlbertABritish ColumBiaNorthwestterritoriesYukonTerriTorYALASKAManitobaNuNavut

B / Azerbaijan – ACG

Profile
• 5.6% interest in 107,000 acres in the Azeri-Chirag-
Gunashli (ACG) oil fields offshore Azerbaijan.
•
Initial position obtained in 1999 merger.
• Major oil export pipeline commenced operations in

2006.

• 64.6 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Commenced production from 11 new wells.
•

Installed platform, production and drilling facilities
in the Deepwater Gunashli area.

2008 Plans
• Drill and complete 16 producing wells.
• Commence production from Deepwater Gunashli

area.

C / China

Profile
• 7.9 million acres in 5 licensed blocks offshore China:

Block 15/34 (Panyu); 24.5% interest.
Block 42/05; 100% interest.
Block 11/34; 100% interest.
Block 53/30; 100% interest.
Block 64/18; 100% interest.

• Located in the South China Sea and Yellow Sea in
water depths ranging from 150’ to 8,200’.
• Panyu fields produce oil from 1998 and 1999

discoveries.

• 19.7 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled and completed 3 development wells at
Panyu, including a successful extended reach well.
• Acquired additional 3-D seismic on block 42/05.
• Acquired blocks 53/30 and 64/18 in South China

Sea.
2008 Plans
• Drill 6 development wells at Panyu.
• Replace subsea pipelines at both Panyu platforms.
• Drill one exploratory well on block 42/05.
• Drill one exploratory well on block 11/34.
• Acquire 2-D and 3-D seismic on block 53/30.
• Acquired 2-D seismic on block 64/18.

INTERNATIONAL

A / Brazil

Profile
• 1.3 million acres in 9 licensed blocks offshore Brazil:

Block BM-C-8 (Polvo); 60% interest.
Block BC-2 (Xerelete); 17.65% interest.
Block BM-BAR-3; 100% interest.
Block BM-C-30; 25% interest.
Block BM-C-32; 40% interest.
Block BM-C-34 (C-M-471); 50% interest.
Block BM-C-34 (C-M-473); 50% interest.
Block BM-C-35; 35% interest.
Block BM-CAL-13; 100% interest.

• Located in the Campos, Barreirinhas and Camamu
Basins in water depths ranging from 330’ to 9,100’.
• Target oil formations at 7,000’ to 16,000’.
• Developing 2004 discovery on block BM-C-8 (Polvo

development).

• 8.9 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Completed platform and FPSO installation and

commissioning operations at Polvo.

• Drilled and completed 3 development wells at Polvo.
• Commenced first production at Polvo.
• Completed exploratory drilling on block BM-C-8

and obtained government approval for an
expanded development area for Polvo.

• Drilled 1 exploratory well on block BC-2 and
submitted a declaration of commerciality for

Initiated 3-D seismic reprocessing on blocks

Xerelete discovery.
• Conducted seabed logging program on block
BM-BAR-3.
• Signed letter of intent to farm out 30% interest in
BM-BAR-3 to an industry partner.
•
BM-C-30, BM-C-32, BM-C-34 and BM-C-35.
• Completed processing of 3-D seismic on block
BM-CAL-13.
• Won onshore blocks PN-T-66 and PN-T-86 in the
Parnaíba Basin in Bid Round 9.
2008 Plans
• Drill and complete 7 development wells at Polvo.
• Reprocess seismic and consider development

options on Xerelete discovery.

• Finalize BM-BAR-3 farm-out agreement and
attempt to farm out additional interest.

• Reprocess and interpret 3-D seismic on blocks
BM-C-30, BM-C-32, BM-C-34 and BM-C-35.
• Drill second exploratory well on BM-C-30.
• Sign concession agreements on blocks PN-T-66

and PN-T-86.

C / Deep Basin

Profile
• 45% average working interest in 1.4 million acres in
western Alberta and eastern British Columbia.
• Key areas include Bilbo, Hiding, Blackhawk, Pinto

and Wapiti.

• Produces liquids-rich gas from primarily Cretaceous

formations at 2,500’ to 14,000’.

• 92.4 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled 41 wells, including:
16 at Wapiti.
15 at Pinto.
5 at Blackhawk.
4 at Bilbo.
1 at Hiding.
2008 Plans
• Drill 49 total wells, including:
15 at Bilbo.
14 at Pinto.
9 at Wapiti.
5 at Blackhawk.
5 at Hiding.

D / Lloydminster

Profile
• 97% working interest in 2.1 million acres in eastern
Alberta and Saskatchewan.
• Key areas include End Lake, Iron River,

Lloydminster and Manatokan.

• Produces primarily conventional, cold flow heavy
oil from multiple formations at 1,000’ to 2,300’.
• 97.2 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Drilled 429 wells, including:
281 at Iron River.
67 at Lloydminster.
40 at End Lake.
28 at Manatokan.
• Completed first capacity expansion of Manatokan

•

processing plant.
Initiated second capacity expansion of Manatokan
processing plant.

2008 Plans
• Drill 475 total wells, including:
318 at Iron River.
53 at Lloydminster.
46 at Manatokan.
42 at End Lake.
• Complete second capacity expansion of Manatokan

processing plant.

E / Thermal heavy Oil

Profile
• 97% average working interest in 75,000 acres in

eastern Alberta oil sands.

• Key asset is Jackfish (100% interest).
• Steam-Assisted Gravity Drainage (SAGD) is the

•

primary recovery method.
Jackfish facility capacity of 35,000 barrels of oil
per day.

• 233.0 million barrels of oil-equivalent reserves at

12/31/07.
2007 Activity
• Completed facility construction and commenced

steam injection at Jackfish.

• Sold first barrel of bitumen near year-end at

Jackfish.

• Began front-end engineering for Jackfish 2, a look-

alike project to Jackfish.

• Completed construction of Access Pipeline.
2008 Plans
• Ramp up production at Jackfish.
•

Initiate construction at Jackfish 2 pending
regulatory approval and internal sanctioning.
• Drill 27 stratigraphic wells to further evaluate the

Jackfish area potential.

IndIan OceanAtlAntic OceAnBrazilCHINAAzerbAijAn

Index to Financials

Selected 11-Year Financial Data

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

Reports of Independent Registered
Public Accounting Firm

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Comprehensive Income 66

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

Risk Factors to Forward-Looking Estimates

109

Devon’s total assets have grown more than 50%
since 2003 to $41.5 billion, while shareholders’ equity
has nearly doubled to $22 billion. The company paid
$249 million in common stock dividends in 2007,
more than six times the 2003 dividend amount.

41.5

35.1

30.0 30.3

27.2

14.9

13.7

11.1

22.0

17.4

249

199

136

Total Assets
($ Billions)

Stockholders’ Equity
($ Billions)

Dividends Paid to Common
Stock ($ Millions)

Selected Eleven-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

Change in fair value of financial instruments
Reduction of carrying value of oil and gas properties
Impairment of Chevron Corporation common stock
Income tax expense (benefit)

Total expenses

Net earnings (loss) before minority interest, cumulative effect of
change in accounting principle and discontinued operations (3)

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
Chevron Corporation common stock (4)

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

$
$

$
$
$
$

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

5-YEAR

COMPOuND

gROwTh RATE

10-YEAR

COMPOuND

gROwTh RATE

497
367
36
10
36

946

288
4

268
—
—
56
—
51
—
633
—
(128)

236
335
25
8
6

436
616
68
20
23

906
1,474
154
53
37

784

1,878

131

909

2,133

275

999

1,218

3,879

404

1,461

104

1,589

4,711

548

1,701

126

1,794

5,761

680

1,792

198

2,434

4,912

749

1,672

115

3,493

5,163

970

1,736

610

1,163

2,624

2,922

4,351

7,066

8,675

10,225

9,882

11,460

231
3

212
—
—
48
13
53
—
354
—
(103)

328
10

379
—
16
83
17
122
—
476
—
(75)

544
28

662
—
41
96
60
155
—
—
—
377

1,172

811

1,356

1,963

2,899

4,292

5,349

6,586

7,328

7,248

8,314

(226)
(218)
12
(230)

(1.67)
(1.67)

137
151

(201)
(236)
—
(236)

(1.66)
(1.66)

142
154

(193)
(154)
4
(158)

(0.84)
(0.84)

187
199

661
730
10
720

2.83
2.75

255
263

1,965

1,931

6,096

6,860

13,184

16,225

27,162

30,025

30,273

35,063

41,456

—
576
50
1,006
142

—
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

3,799

11,056

472

692

6,339

4,596

13,674

484

709

5,248

4,977

14,862

443

727

4,841

5,290

17,442

444

641

6,283

6,042

22,006

444

666

831

—

114

220

979

—

103

0.37

0.36

255

259

886

808

1,224

1,174

1,439

1,339

1,579

1,342

1,766

1,236

2,168

1,227

1,211

1,609

1,982

1,924

2,231

2,858

—

219

—

533

(28)

651

205

(193)

104

0.31

0.30

309

313

—

306

502

(1)

—

453

1,717

1,747

1,737

4.16

4.04

417

433

—

277

—

475

—

970

2,089

2,186

2,176

4.51

4.38

482

499

—

291

—

533

—

1,481

2,897

2,930

2,920

6.38

6.26

458

470

—

397

—

421

178

—

936

2,634

2,846

2,836

6.42

6.34

442

448

—

513

—

430

(34)

—

1,078

3,146

3,606

3,596

8.08

8.00

445

450

31%

19%

29%

12%

23%

21%

20%

19%

N/M

19%

N/M

-4%

N/M

14%

122%

103%

107%

93%

21%

-1%

-2%

18%

36%

22%

30%

39%

N/M

11%

28%

22%

N/M

27%

N/M

25%

N/M

24%

N/M

22%

N/M

-2%

N/M

12%

36%

N/M

27%

62%

36%

12%

(1) The years 1997 to 2002 exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002. The years 2003 through 2007 exclude results from operations

in Africa that were discontinued in 2006 and 2007. All periods prior to the November 15, 2004 two-for-one stock split have been adjusted to reflect the split.

(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) Before minority interest in Monterrey Resources, Inc. of ($5) million in 1997, 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 $13, ($35) $39, $69, $31, $45, $14, $97, $33, $212 and $460 million in 1997 through 2007, respectively.

(4) Devon owns 14.2 million shares of Chevron Corporation common stock. The majority of these shares are on deposit with an exchange agent for possible exchange for $652 million principal

amount of exchangeable debentures. The Chevron shares and debentures were acquired through the 1999 acquisition of PennzEnergy.

N/M Not a meaningful number.

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

5-YEAR
COMPOuND
gROwTh RATE

10-YEAR
COMPOuND
gROwTh RATE

Total revenues

610

1,163

2,624

2,922

4,351

7,066

8,675

10,225

9,882

11,460

784
1,878
131
71
58

909
2,133
275
999
35

1,218
3,879
404
1,461
104

1,589
4,711
548
1,701
126

1,794
5,761
680
1,792
198

2,434
4,912
749
1,672
115

3,493
5,163
970
1,736
98

666
47

831
—
34
114
1
220
2
979
—
5

886
808

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

1,224
1,174

1,609
35
—
306
7
502
(1)
40
—
453

1,439
1,339

1,982
42
—
277
—
475
62
—
—
970

1,579
1,342

1,924
42
—
291
—
533
94
42
—
1,481

1,766
1,236

2,231
47
—
397
—
421
178
36
—
936

2,168
1,227

2,858
74
—
513
—
430
(34)
—
—
1,078

Total expenses

1,172

811

1,356

1,963

2,899

4,292

5,349

6,586

7,328

7,248

8,314

23
103
10
93

0.37
0.36

255
259

59
104
10
94

0.31
0.30

309
313

1,717
1,747
10
1,737

4.16
4.04

417
433

2,089
2,186
10
2,176

4.51
4.38

482
499

2,897
2,930
10
2,920

6.38
6.26

458
470

2,634
2,846
10
2,836

6.42
6.34

442
448

3,146
3,606
10
3,596

8.08
8.00

445
450

1,965

1,931

6,096

6,860

13,184

16,225

27,162

30,025

30,273

35,063

41,456

—

576

1,006

142

—

885

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
3,799
11,056
472

692
6,339
4,596
13,674
484

709
5,248
4,977
14,862
443

727
4,841
5,290
17,442
444

641
6,283
6,042
22,006
444

OPERATING RESULTS (In millions, except per share data)

Revenues (Net of royalties):

Oil sales

Gas sales

NGL sales

Marketing and midstream revenues

Other income

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

Change in fair value of financial instruments

Reduction of carrying value of oil and gas properties

Impairment of Chevron Corporation common stock

Income tax expense (benefit)

Net earnings (loss) before minority interest, cumulative effect of

change in accounting principle and discontinued operations (3)

Net earnings (loss)

Preferred stock dividends

Net earnings (loss) to common stockholders

Net earnings (loss) per common share:

Weighted average shares outstanding:

Basic

Diluted

Basic

Diluted

BALANCE SHEET DATA (In millions)

Total assets

Debentures exchangeable into shares of

Chevron Corporation common stock (4)

Other long-term debt

Deferred income taxes

Stockholders’ equity

Common shares outstanding

497

367

946

288

268

—

633

—

(128)

(226)

(218)

(230)

(1.67)

137

151

236

335

231

212

—

354

—

(103)

(201)

(236)

—

(236)

(1.66)

142

154

436

616

328

379

—

122

—

476

—

(75)

(193)

(154)

(158)

(0.84)

187

199

906

1,474

154

544

662

—

155

—

377

661

730

720

2.83

2.75

255

263

(1) The years 1997 to 2002 exclude results from Devon’s operations in Indonesia, Argentina and Egypt that were discontinued in 2002. The years 2003 through 2007 exclude results from operations

in Africa that were discontinued in 2006 and 2007. All periods prior to the November 15, 2004 two-for-one stock split have been adjusted to reflect the split.

(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) Before minority interest in Monterrey Resources, Inc. of ($5) million in 1997, 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 $13, ($35) $39, $69, $31, $45, $14, $97, $33, $212 and $460 million in 1997 through 2007, respectively.

(4) Devon owns 14.2 million shares of Chevron Corporation common stock. The majority of these shares are on deposit with an exchange agent for possible exchange for $652 million principal

amount of exchangeable debentures. The Chevron shares and debentures were acquired through the 1999 acquisition of PennzEnergy.

N/M Not a meaningful number.

31%
19%
29%
12%
23%

21%

20%
9%

19%
N/M
N/M
19%
N/M
-4%
4%
N/M
N/M
N/M

14%

122%
103%
0%
107%

93%
93%

8%
8%

21%

-1%
-2%
18%
36%
7%

22%
30%
39%
N/M
11%

28%

22%
N/M

27%
N/M
N/M
25%
N/M
24%
N/M
N/M
N/M
N/M

22%

N/M
N/M
-2%
N/M

N/M
N/M

12%
12%

36%

N/M
27%
62%
36%
12%

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

Overview of 2007 Results and Outlook

2007 was Devon’s best year in its 20-year history as a public company. We achieved key operational successes and

continued to execute our strategy to increase value per share. As a result, we delivered record amounts for earnings,
earnings per share and operating cash flow, and also grew proved reserves to a new all-time high. Key measures of our
financial and operating performance for 2007, as well as certain operational developments, are summarized below:

Production grew 12% over 2006, to 224 million Boe

•
• Net earnings rose 27%, reaching an all-time high of $3.6 billion
• Diluted net earnings per share increased 26% to a record $8.00 per diluted share
• Net cash provided by operating activities reached $6.7 billion, representing an 11% increase over 2006
•
• Discoveries, extensions and performance revisions added 390 million Boe of proved reserves, or 17% of the

Estimated proved reserves reached a record amount of 2.5 billion Boe

beginning-of-year proved reserves

• Capital expenditures for oil and gas exploration and development activities were $5.8 billion
•
• Marketing and midstream operating profit climbed to a record $509 million

The combined realized price for oil, gas and NGLs per Boe increased 6% to $42.96

Operating costs increased due to the 12% growth in production, inflationary pressure driven by increased competition
for field services and the weakened U.S. dollar compared to the Canadian dollar. Per unit lease operating expenses increased
15% to $8.16 per Boe.

During 2007, we used $6.2 billion of cash flow from continuing operations along with other capital resources to fund $6.2
billion of capital expenditures, reduce debt obligations by $567 million, repurchase $326 million of our common stock and pay
$259 million in dividends to our stockholders. We also ended the year with $1.7 billion of cash and short-term investments.

From an operational perspective, we completed another successful year with the drill-bit. We drilled 2,440 wells with an
overall 98% rate of success. This success rate enabled us to increase our proved reserves by 9% to a record of 2.5 billion Boe
at the end of 2007. We added 390 MMBoe of proved reserves during the year with extensions, discoveries and performance
revisions, which was well in excess of the 224 MMBoe we produced during the year. Consistent with our two-pronged
operating strategy, 92% of the wells we drilled were North American development wells.

Besides completing another successful year of drilling, we also had several other key operational achievements during

2007. In the Gulf of Mexico, we continued to build upon prior years’ successful drilling results with our deepwater
exploration and development program. We commenced production from the Merganser field, and we also began drilling our
first operated exploratory well in the Lower Tertiary trend of the Gulf of Mexico. We also made progress toward commercial
development of our four previous discoveries in the Lower Tertiary trend.

At our 100%-owned Jackfish thermal heavy oil project in the Alberta oil sands, we completed construction and

commenced steam injection. Oil production from Jackfish is expected to ramp up throughout 2008 toward a peak production
target of 35,000 Bbls per day. Additionally, we began front-end engineering and design work on an extension of our Jackfish
project. Like the first phase, this second phase of Jackfish is also expected to eventually produce 35,000 Bbls per day.

Finally, we completed construction and fabrication of the Polvo oil development project offshore Brazil and began
producing oil from the first of ten planned wells. Polvo, located in the Campos basin, was discovered in 2004 and is our first
operated development project in Brazil.

In November 2006 and January 2007, we announced plans to divest our operations in Egypt and West Africa, including

Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region. Divesting these properties will allow us to
redeploy our financial and intellectual capital to the significant growth opportunities we have developed onshore in North
America and in the deepwater Gulf of Mexico. Additionally, we will sharpen our focus in North America and concentrate our
international operations in Brazil and China, where we have established competitive advantages.

In October 2007, we completed the sale of our operations in Egypt and received proceeds of $341 million. As a result of

this sale, we recognized a $90 million after-tax gain in the fourth quarter of 2007. In November 2007, we announced an

MD&A

agreement to sell our operations in Gabon for $205.5 million. We are finalizing purchase and sales agreements and obtaining
the necessary partner and government approvals for the remaining properties in the West African divestiture package. We
are optimistic we can complete these sales during the first half of 2008 and then primarily use the proceeds to repay our
outstanding commercial paper and revolving credit facility borrowings and resume common stock repurchases.

Looking to 2008, we announced in February 2008 that we have hedged a meaningful portion of our expected 2008 pro-
duction with financial price collar and swap arrangements. As of February 15, 2008, approximately 62% of our expected 2008
gas production is subject to either price collars with a floor price of $7.50 per MMBtu and an average ceiling price of $9.43
per MMBtu, or price swaps with an average price of $8.24 per MMBtu. Another 2% of our expected 2008 gas production is
subject to fixed-price physical contracts. Also, as of February 15, 2008, approximately 12% of our expected 2008 oil produc-
tion is subject to price collars with a floor price of $70.00 per barrel and an average ceiling price of $140.23 per barrel.

Additionally, our operational accomplishments in recent years have laid the foundation for continued growth in future

years, at competitive unit costs, which we expect will continue to create additional value for our investors. In 2008, we
expect to deliver proved reserve additions of 390 to 410 million Boe with related capital expenditures in the range of $6.1 to
$6.4 billion. We expect production to increase approximately 9% from 2007 to 2008, which reflects our significant reserve
additions in recent years as well as those expected in 2008. Additionally, our exploration program exposes us to high-impact
projects in North America and international locations that can fuel more growth in the years to come.

Results of Operations

Revenues

Changes in oil, gas and NGL production, prices and revenues from 2005 to 2007 are shown in the following tables. The
amounts for all periods presented exclude results from our Egyptian and West African operations which are presented as
discontinued operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.

Production
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)(1)
Average Prices
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Combined (per Boe)(1)
Revenues ($ in millions)
Oil
Gas
NGLs
Total

2007

55
863
26
224

63.98
5.99
37.76
42.96

3,493
5,163
970
9,626

2007

19
635
22
146

69.23
5.89
36.11
39.87

1,313
3,742
773
5,828

$
$
$
$

Total
Year Ended December 31,

2006

42
808
23
200

57.39
6.08
32.10
40.38

2,434
4,912
749
8,095

Domestic
Year Ended December 31,

2006

19
566
19
132

62.23
6.09
29.42
39.31

1,218
3,445
548
5,211

2007 vs
2006 (2)

+29%
+7%
+10%
+12%

+11%
-1%
+18%
+6%

+44%
+5%
+30%
+19%

2007 vs
2006 (2)

-3%
+12%
+15%
+10%

+11%
-3%
+23%
+1%

+8%
+9%
+41%
+12%

2006 vs
2005 (2)

-9%
-1%
—
-3%

+49%
-14%
+11%
+1%

+36%
-15%
+10%
-2%

2006 vs
2005 (2)

-23%
+2%
+3%
-3%

+49%
-14%
+10%
-2%

+15%
-12%
+13%
-5%

2005

46
819
24
206

38.64
7.03
29.05
39.89

1,794
5,761
680
8,235

2005

25
555
18
136

41.64
7.08
26.68
40.21

1,062
3,929
484
5,475

MD&A

Production
Oil (MMBbls)
Gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)(1)
Average Prices
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Combined (per Boe)(1)
Revenues ($ in millions)
Oil
Gas
NGLs
Total

2007

16
227
4
58

49.80
6.24
46.07
41.51

804
1,410
197
2,411

2007

20
1
—
20

70.60
6.22
—
70.11

1,376
11
—
1,387

$
$
$
$

Canada
Year Ended December 31,

2006

13
241
4
58

46.94
6.05
42.67
39.21

603
1,456
201
2,260

International
Year Ended December 31,

2006

10
1
—
10

61.35
6.05
—
60.60

613
11
—
624

2007 vs
2006 (2)

+26%
-6%
-9%
+1%

+6%
+3%
+8%
+6%

+33%
-3%
-2%
+7%

2007 vs
2006 (2)

+95%
-6%
N/M
+92%

+15%
+3%
N/M
+16%

+125%
-3%
N/M
+122%

2006 vs
2005 (2)

-2%
-8%
-11%
-7%

+75%
-13%
+15%
+3%

+71%
-20%
+2%
-4%

2006 vs
2005 (2)

+28%
-42%
N/M
+23%

+26%
+12%
N/M
+27%

+61%
-35%
N/M
+57%

2005

13
261
6
62

26.88
6.95
37.19
38.17

353
1,814
196
2,363

2005

8
3
—
8

48.59
5.42
—
47.57

379
18
—
397

(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 gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
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.

The average prices shown in the preceding tables include the effect of our oil and gas price hedging activities. Following is

a comparison of our average prices with and without the effect of hedges for each of the last three years.

Realized price without hedges
Cash settlements
Realized cash price
Net unrealized losses
Realized price with hedges

Realized price without hedges
Cash settlements
Realized cash price
Net unrealized gains
Realized price with hedges

Oil
(Per Bbl)

63.98
—
63.98
—
63.98

Oil
(Per Bbl)

57.39
—
57.39
—
57.39

Year Ended December 31, 2007

gas
(Per Mcf)

NgLs
(Per Bbl)

5.97
0.04
6.01
(0.02)
5.99

37.76
—
37.76
—
37.76

Year Ended December 31, 2006

gas
(Per Mcf)

NgLs
(Per Bbl)

6.03
—
6.03
0.05
6.08

32.10
—
32.10
—
32.10

Total
(Per Boe)

42.90
0.18
43.08
(0.12)
42.96

Total
(Per Boe)

40.19
—
40.19
0.19
40.38

Realized price without hedges
Cash settlements
Realized price with hedges

Oil
(Per Bbl)

48.01
(9.37)
38.64

Year Ended December 31, 2005

gas
(Per Mcf)

NgLs
(Per Bbl)

7.08
(0.05)
7.03

29.05
—
29.05

MD&A

Total
(Per Boe)

42.18
(2.29)
39.89

The following table details the effects of changes in volumes and prices on our oil, gas and NGL revenues between 2005

and 2007.

2005 revenues

Changes due to volumes
Changes due to realized cash prices
Changes due to net unrealized hedge gains

2006 revenues

Changes due to volumes
Changes due to realized cash prices
Changes due to net unrealized hedge losses

2007 revenues

Oil Revenues

Oil

gas

NgLs

Total

(In millions)

1,794
(155)
795
—
2,434
700
359
—
3,493

5,761
(77)
(809)
37
4,912
329
(53)
(25)
5,163

680
(2)
71
—
749
76
145
—
970

8,235
(234)
57
37
8,095
1,105
451
(25)
9,626

2007 vs. 2006 Oil revenues increased $700 million due to a 13 million barrel increase in production. The increase in our
2007 oil production was primarily due to our properties in Azerbaijan where we achieved payout of certain carried interests
in the last half of 2006. This led to a nine million barrel increase in 2007 as compared to 2006. Production also increased 3.5
million barrels due to increased development activity in our Lloydminster area in Canada. Also, oil sales from our Polvo field
in Brazil began during the fourth quarter of 2007, which resulted in 0.5 million barrels of increased production.

Oil revenues increased $359 million as a result of an 11% increase in our realized price. The average NYMEX West Texas

Intermediate index price increased 9% during the same time period, accounting for the majority of the increase.

2006 vs. 2005 Oil revenues decreased $155 million due to a four million barrel decrease in production. Production lost
from properties divested in 2005 caused a decrease of four million barrels, and production declines related to our U.S. and
Canadian properties caused a decrease of three million barrels. These decreases were partially offset by a three million barrel
increase from reaching payout of certain carried interests in Azerbaijan.

Oil revenues increased $795 million as a result of a 49% increase in our realized price. The expiration of oil hedges at the

end of 2005 and a 17% increase in the average NYMEX West Texas Intermediate index price caused the increase in our
realized oil price.

Gas Revenues

2007 vs. 2006 A 55 Bcf increase in production caused gas revenues to increase by $329 million. Our drilling and

development program in the Barnett Shale field in north Texas contributed 53 Bcf to the gas production increase. The June
2006 Chief Holdings LLC (“Chief”) acquisition also contributed 12 Bcf of increased production. During 2007, we also began
first production from the Merganser field in the deepwater Gulf of Mexico, which resulted in seven Bcf of increased
production. These increases and the effects of new drilling and development in our other North American properties were
partially offset by natural production declines primarily in Canada.

A 1% decline in our average realized price caused gas revenues to decrease $78 million in 2007.
2006 vs. 2005 An 11 Bcf decrease in production caused gas revenues to decrease by $77 million. Production lost from the

2005 property divestitures caused a decrease of 35 Bcf. As a result of Hurricanes Katrina, Rita, Dennis and Ivan which
occurred in 2005, gas volumes suspended in 2006 were three Bcf more than those suspended in 2005. These decreases were
partially offset by the June 2006 Chief acquisition, which contributed 10 Bcf of production during the last half of 2006, and
additional production from new drilling and development in our U.S. onshore and offshore properties.

A 14% decline in average prices caused gas revenues to decrease $772 million in 2006. The 2005 average gas price was

impacted by the supply disruptions caused by that year’s hurricanes.

MD&A

Marketing and Midstream Revenues and Operating Costs and Expenses

The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting

operating profit between 2005 and 2007 are shown in the table below.

Marketing and midstream ($ in millions):

Revenues
Operating costs and expenses
Operating profit

2007

1,736
1,227
509

Year Ended December 31,

2007 vs
2006 (1)

+4%
-1%
+17%

2006

1,672
1,236
436

2006 vs
2005 (1)

-7%
-8%
-3%

2005

1,792
1,342
450

(1)

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

2007 vs. 2006 Marketing and midstream revenues increased $64 million, while operating costs and expenses decreased $9

million, causing operating profit to increase $73 million. Revenues increased primarily due to higher prices realized on NGL
sales.

2006 vs. 2005 Marketing and midstream revenues decreased $120 million, and operating costs and expenses also
decreased $106 million, causing operating profit to decrease $14 million. Both revenues and expenses in 2006 decreased
primarily due to lower natural gas prices, partially offset by the effect of higher gas pipeline throughput.

Oil, Gas and NGL Production and Operating Expenses

The details of the changes in oil, gas and NGL production and operating expenses between 2005 and 2007 are shown in

the table below.

Production and operating expenses ($ in millions):

Lease operating expenses
Production taxes
Total production and operating expenses
Production and operating expenses per Boe:

Lease operating expenses
Production taxes
Total production and operating expenses per Boe

2007

1,828
340
2,168

8.16
1.52
9.68

2007 vs
2006 (1)

+28%
—
+23%

+15%
-11%
+10%

Year Ended December 31,

2006

1,425
341
1,766

7.11
1.70
8.81

2006 vs
2005 (1)

+15%
+ 2%
+12%

+18%
+ 5%
+15%

2005

1,244
335
1,579

6.03
1.62
7.65

(1)

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

Lease Operating Expenses (“LOE”)

2007 vs. 2006 LOE increased $403 million in 2007. The largest contributor to this increase was our 12% growth in

production, which caused an increase of $168 million. Another key contributor to the LOE increase was the continued effects
of inflationary pressure driven by increased competition for field services. Increased demand for these services continue to
drive costs higher for materials, equipment and personnel used in both recurring activities as well as well-workover projects.
Furthermore, changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $40 million.

2006 vs. 2005 LOE increased $181 million in 2006 largely due to higher commodity prices. Commodity price increases in

2005 and the first half of 2006 contributed to industry-wide inflationary pressures on materials and personnel costs.
Additionally, the availability of higher commodity prices contributed to our decision to perform more well workovers and
maintenance projects to maintain or improve production volumes. Commodity price increases also caused operating costs
such as ad valorem taxes, power and fuel costs to rise.

A higher Canadian-to-U.S. dollar exchange rate in 2006 caused LOE to increase $34 million. LOE also increased $33 million

due to the June 2006 Chief acquisition and the payouts of our carried interests in Azerbaijan in the last half of 2006. The
increases in our LOE were partially offset by a decrease of $82 million related to properties that were sold in 2005.

The factors described above were also the primary factors causing LOE per Boe to increase during 2006. Although we
divested properties in 2005 that had higher per-unit operating costs, the cost escalation largely related to higher commodity
prices and the weaker U.S. dollar had a greater effect on our per unit costs than the property divestitures.

Production Taxes

The following table details the changes in production taxes between 2005 and 2007. The majority of our 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 changes due to revenues in the table primarily relate to changes in oil, gas and NGL revenues
from our U.S. onshore properties.

MD&A

2005 production taxes

Change due to revenues
Change due to rate
2006 production taxes

Change due to revenues
Change due to rate
2007 production taxes

(In millions)

335
(25)
31
341
65
(66)
340

2007 vs. 2006 Production taxes decreased $66 million due to a decrease in the effective production tax rate in 2007. Our
lower production tax rates in 2007 were primarily due to an increase in tax credits received on certain horizontal wells in the
state of Texas and the increase in Azerbaijan revenues subsequent to the payouts of our carried interests in the last half of
2006. Our Azerbaijan revenues are not subject to production taxes. Therefore, the increased revenues generated in
Azerbaijan in 2007 caused our overall rate of production taxes to decrease.

2006 vs. 2005 Production taxes increased $31 million due to an increase in the effective production tax rate in 2006. A

new Chinese “Special Petroleum Gain” tax was the primary contributor to the higher rate.

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

DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced

during the year, by the “depletable base.” The depletable base represents our net capitalized investment plus future
development costs related to proved undeveloped reserves. 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.

The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties between 2005 and 2007

are shown in the table below.

Total production volumes (MMBoe)
DD&A rate ($ per Boe)
DD&A expense ($ in millions)

2007

224
11.85
2,655

$
$

Year Ended December 31,

2007 vs
2006 (1)

+12%
+15%
+29%

2006

200
10.27
2,058

2006 vs
2005 (1)

-3%
+20%
+16%

2005

206
8.56
1,767

(1)

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

The following table details the increases and decreases in DD&A of oil and gas properties between 2005 and 2007 due to

the changes in production volumes and DD&A rate presented in the table above.

2005 DD&A

Change due to volumes
Change due to rate

2006 DD&A

Change due to volumes
Change due to rate

2007 DD&A

(In millions)

1,767
(51)
342
2,058
242
355
2,655

MD&A

2007 vs. 2006 The 12% production increase caused oil and gas property related DD&A to increase $242 million. In
addition, oil and gas property related DD&A increased $355 million due to a 15% increase in the DD&A rate. The largest
contributor to the rate increase was inflationary pressure on both the costs incurred during 2007 as well as the estimated
development costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate
increase include the transfer of previously unproved costs to the depletable base as a result of 2007 drilling activities and a
higher Canadian-to-U.S. dollar exchange rate in 2007. The effect of these increases was partially offset by a decrease
resulting from higher reserve estimates due to the effects of higher 2007 year-end commodity prices.

2006 vs. 2005 The 3% production decrease caused oil and gas property related DD&A to decrease $51 million. However,
oil and gas property related DD&A increased $342 million due to a 20% increase in the DD&A rate. The largest contributor to
the rate increase was inflationary pressure on both the costs incurred during 2006 as well as the estimated development
costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to the rate increase included
the June 2006 Chief acquisition and the transfer of previously unproved costs to the depletable base as a result of 2006
drilling activities. A reduction in reserve estimates due to the effects of lower 2006 year-end commodity prices also
contributed to the rate increase.

General and Administrative Expenses (“G&A”)

Our 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 we serve 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

2007

947
(312)
(122)
513

Year Ended December 31,

2007 vs
2006 (1)

+26%
+28%
+12%
+29%

2006

(In millions)

749
(243)
(109)
397

2006 vs
2005 (1)

+34%
+54%
-2%
+36%

2005

560
(158)
(111)
291

(1)

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

2007 vs. 2006 Gross G&A increased $198 million. The largest contributors to this increase were higher employee

compensation and benefits costs. These cost increases, which were related to our continued growth and industry inflation,
caused gross G&A to increase $134 million. Of this increase, $55 million related to higher stock compensation. In addition,
changes in the Canadian-to-U.S. dollar exchange rate caused a $13 million increase in costs.

2006 vs. 2005 Gross G&A increased $189 million. Higher employee compensation and benefits costs caused gross G&A
to increase $148 million. Of this increase, $34 million represented stock option expense recognized pursuant to our adoption
in 2006 of Statement of Financial Accounting Standard No. 123(R), Share-Based Payment. An additional $28 million of the
increase related to higher restricted stock compensation. In addition, changes in the Canadian-to-U.S. dollar exchange rate
caused an $11 million increase in costs.

The factors discussed above were also the primary factors that caused the $69 million and $85 million increases in

capitalized G&A in 2007 and 2006, respectively.

Interest Expense

The following schedule includes the components of interest expense between 2005 and 2007.

Interest based on debt outstanding

Capitalized interest
Other interest

Total interest expense

2007

Year Ended December 31,
2006

2005

508
(102)
24
430

(In millions)

486
(79)
14
421

507
(70)
96
533

MD&A

Interest based on debt outstanding increased $22 million from 2006 to 2007. This increase was largely due to higher
average outstanding amounts for commercial paper and credit facility borrowings in 2007 than in 2006, partially offset by
the effects of repaying various maturing notes in 2007 and 2006. Interest based on debt outstanding decreased $21 million
from 2005 to 2006 primarily due to the repayment of various maturing notes in 2005 and 2006, partially offset by an
increase in commercial paper borrowings during 2006 to fund the June 2006 Chief acquisition.

Capitalized interest increased from 2005 to 2007 primarily due to higher cumulative costs related to the development of

the second phase of our Jackfish heavy oil development project in Canada and the construction of the related Access
Pipeline. Higher development costs in the Gulf of Mexico and Brazil also contributed to the increase.

During 2005, we redeemed our $400 million 6.75% notes due March 15, 2011 and our zero coupon convertible senior
debentures prior to their scheduled maturity dates. The other interest category in the table above includes $81 million in
2005 related to these early retirements.

Change in Fair Value of Financial Instruments

The details of the changes in fair value of financial instruments between 2005 and 2007 are shown in the table below.

Losses (gains) from:

Option embedded in exchangeable debentures
Chevron common stock
Interest rate swaps

Non-qualifying commodity hedges

Ineffectiveness of commodity hedges
Total change in fair value of financial instruments

2007

Year Ended December 31,
2006

2005

(In millions)

248
(281)
(1)
—
—
(34)

181
—
(3)
—
—
178

54
—
(4)
39
5
94

The change in the fair value of the embedded option relates to the debentures exchangeable into shares of Chevron

common stock. These unrealized losses were caused primarily by increases in the price of Chevron’s common stock.

Effective January 1, 2007 as a result of our adoption of Financial Accounting Standard No. 159, The Fair Value Option for

Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, we began recognizing
unrealized gains and losses on our investment in Chevron common stock in net earnings rather than as part of other
comprehensive income. The change in fair value of our investment in Chevron common stock resulted from an increase in
the price of Chevron’s common stock during 2007.

In 2005, we recognized a $39 million loss on certain oil derivative financial instruments that no longer qualified for hedge
accounting because the hedged production exceeded actual and projected production under these contracts. The lower than
expected production was caused primarily by hurricanes that affected offshore production in the Gulf of Mexico.

Reduction of Carrying Value of Oil and Gas Properties

During 2006 and 2005, we reduced the carrying value of certain of our oil and gas properties due to full cost ceiling
limitations and unsuccessful exploratory activities. A detailed description of how full cost ceiling limitations are determined
is included in the “Critical Accounting Policies and Estimates” section of this report. A summary of these reductions and
additional discussion is provided below.

Brazil - unsuccessful exploratory reduction
Russia - ceiling test reduction

Total

2006 Reductions

Year Ended December 31,

2006

2005

gross

Net of
Taxes

gross

Net of
Taxes

(In millions)

16
20
36

16
10
26

42
—
42

During the second quarter of 2006, we drilled two unsuccessful exploratory wells in Brazil and determined that the
capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, we recognized a
$16 million impairment of our investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of
block-related costs. There was no tax benefit related to this impairment. The two wells were unrelated to our Polvo
development project in Brazil.

MD&A

As a result of a decline in projected future net cash flows, the carrying value of our Russian properties exceeded the full

cost ceiling by $10 million at the end of the third quarter of 2006. Therefore, we recognized a $20 million reduction of the
carrying value of our oil and gas properties in Russia, offset by a $10 million deferred income tax benefit.

2005 Reduction

Prior to the fourth quarter of 2005, we were capitalizing the costs of previous unsuccessful efforts in Brazil pending the
determination of whether proved reserves would be recorded in Brazil. At the end of 2005, it was expected that a small initial
portion of the proved reserves ultimately expected at Polvo would be recorded in 2006. Based on preliminary estimates
developed in the fourth quarter of 2005, the value of this initial partial booking of proved reserves was not sufficient to offset
the sum of the related proportionate Polvo costs plus the costs of the previous unrelated unsuccessful efforts. Therefore, we
determined that the prior unsuccessful costs unrelated to the Polvo project should be impaired. These costs totaled
approximately $42 million. There was no tax benefit related to this Brazilian impairment.

Other Income, Net

The following schedule includes the components of other income between 2005 and 2007.

Interest and dividend income

Net gain on sales of non-oil and gas property and equipment
Loss on derivative financial instruments
Other

Total

2007

Year Ended December 31,
2006

2005

(In millions)

89
1
—
8
98

100
5
—
10
115

95
150
(48)
1
198

Interest and dividend income decreased from 2006 to 2007 primarily due to a decrease in income-earning cash and
investment balances, partially offset by an increase in the dividend rate on our investment in Chevron common stock.
Interest and dividend income increased from 2005 to 2006 primarily due to an increase in cash and short-term investment
balances and higher interest rates.

During 2005, we sold certain non-core midstream assets for a net gain of $150 million. Also during 2005, we incurred a
$55 million loss on certain commodity hedges that no longer qualified for hedge accounting and were settled prior to the end
of their original term. These hedges related to U.S. and Canadian oil production from properties sold as part of our 2005
property divestiture program. This loss was partially offset by a $7 million gain related to interest rate swaps that were
settled prior to the end of their original term in conjunction with the early redemption of the $400 million 6.75% senior notes
in 2005.

Income Taxes

The following table presents our total income tax expense related to continuing operations and a reconciliation of our
effective income tax rate to the U.S. statutory income tax rate for each of the past three years. The primary factors causing
our effective rates to vary from 2005 to 2007, and differ from the U.S. statutory rate, are discussed below.

Total income tax expense (In millions)

1,078

936

1,481

2007

Year Ended December 31,
2006

2005

U.S. statutory income tax rate
Canadian statutory rate reductions
Texas income-based tax
Repatriation of earnings
Other, primarily taxation on foreign operations
Effective income tax rate

35%
(6%)
—
—
(3%)
26%

35%
(7%)
1%
—
(3%)
26%

35%
—
—
1%
(2%)
34%

In 2007, 2006 and 2005, deferred income taxes were reduced $261 million, $243 million and $14 million, respectively, due

to successive Canadian statutory rate reductions that were enacted in each such year.

In 2006, deferred income taxes increased $39 million due to the effect of a new income-based tax enacted by the state of

Texas that replaced a previous franchise tax. The new tax was effective January 1, 2007.

MD&A

In 2005, we recognized $28 million of taxes related to our repatriation of $545 million to the United States. The cash was

repatriated to take advantage of U.S. tax legislation that allowed qualifying companies to repatriate cash from foreign
operations at a reduced income tax rate. Substantially all of the cash repatriated by us in 2005 related to prior earnings of
our Canadian subsidiary.

Earnings From Discontinued Operations

In November 2006 and January 2007, we announced our plans to divest our operations in Egypt and West Africa,
including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region. Pursuant to accounting rules for
discontinued operations, we have classified all 2007 and prior period amounts related to our operations in Egypt and West
Africa as discontinued operations.

In October 2007, we completed the sale of our Egyptian operations and received proceeds of $341 million. As a result of

this sale, we recognized a $90 million after-tax gain in the fourth quarter of 2007. In November 2007, we announced an
agreement to sell our operations in Gabon for $205.5 million. We are finalizing purchase and sales agreements and obtaining
the necessary partner and government approvals for the remaining properties in the West African divestiture package. We
are optimistic we can complete these sales during the first half of 2008.

Following are the components of earnings from discontinued operations between 2005 and 2007.

Earnings from discontinued operations before income taxes

Income tax expense
Earnings from discontinued operations

2007

Year Ended December 31,
2006

2005

696
236
460

(In millions)

464
252
212

173
140
33

2007 vs. 2006 Earnings from discontinued operations increased $248 million in 2007. In addition to variances caused by

changes in production volumes and realized prices, our earnings from discontinued operations in 2007 were impacted by
other significant factors. Pursuant to accounting rules for discontinued operations, we ceased recording DD&A in November
2006 related to our Egyptian operations and in January 2007 related to our West African operations. This reduction in DD&A
caused earnings from discontinued operations to increase $119 million in 2007. Earnings in 2007 also benefited from the $90
million gain from the sale of our Egyptian operations.

In addition, earnings from discontinued operations increased $90 million in 2007 due to the net effect of reductions in
carrying value in 2006 and 2007. Our earnings in 2007 were reduced by $13 million from these reductions, compared to $103
million of reductions recorded in 2006. Due to unsuccessful drilling activities in Nigeria, in the first quarter of 2006, we
recognized an $85 million impairment of our investment in Nigeria equal to the costs to drill two dry holes and a
proportionate share of block-related costs. There was no income tax benefit related to this impairment. As a result of
unsuccessful exploratory activities in Egypt during 2006, the net book value of our Egyptian oil and gas properties, less
related deferred income taxes, exceeded the ceiling by $18 million as of the end of September 30, 2006. Therefore, in 2006
we recognized an $18 million after-tax loss ($31 million pre-tax). In the second quarter of 2007, based on drilling activities in
Nigeria, we recognized a $13 million after-tax loss ($64 million pre-tax).

2006 vs. 2005 Earnings from discontinued operations increased $179 million in 2006. This increase was largely due to an

increase in realized crude oil prices, partially offset by a 19% decline in oil production.

In addition, earnings from discontinued operations increased $16 million due to the net effect of a $119 million after-tax

impairment of our investment in Angola in 2005, partially offset by the 2006 Nigerian and Egyptian impairments totaling
$103 million as described above. Our interests in Angola were acquired through the 2003 Ocean Energy merger, and our
Angolan drilling program discovered no proven reserves. After drilling three unsuccessful wells in the fourth quarter of 2005,
we determined that all of the Angolan capitalized costs should be impaired. As a result, we recognized a $170 million
impairment with a $51 million related tax benefit.

Capital Resources, uses and Liquidity

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

financial statements included in this report.

MD&A

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents from 2005 to 2007. The table
presents capital expenditures on a cash basis. Therefore, these amounts differ from the amounts of capital expenditures,
including accruals, that are referred to elsewhere in this document. Additional discussion of these items follows the table.

Sources of cash and cash equivalents:

Operating cash flow – continuing operations
Sales of property and equipment
Net credit facility borrowings
Net commercial paper borrowings
Net decrease in short-term investments
Stock option exercises
Other
Total sources of cash and cash equivalents

Uses of cash and cash equivalents:

Capital expenditures
Net commercial paper repayments
Debt repayments
Repurchases of common stock
Dividends
Total uses of cash and cash equivalents

Increase (decrease) from continuing operations
Increase from discontinued operations

Effect of foreign exchange rates
Net increase (decrease) in cash and cash equivalents

Cash and cash equivalents at end of year
Short-term investments at end of year

Operating Cash Flow – Continuing Operations

2007

2006

2005

(In millions)

$
$

6,162
76
1,450
—
202
91
44
8,025

(6,158)
(804)
(567)
(326)
(259)
(8,114)

(89)
655
51
617

1,373
372

5,374
40
—
1,808
106
73
36
7,437

(7,346)
—
(862)
(253)
(209)
(8,670)

(1,233)
370
13
(850)

756
574

5,297
2,151
—
—
287
124
—
7,859

(3,813)
—
(1,258)
(2,263)
(146)
(7,480)

379
38
37
454

1,606
680

Net cash provided by operating activities (“operating cash flow”) continued to be our primary source of capital and
liquidity in 2007. Changes in operating cash flow are largely due to the same factors that affect our net earnings, with the
exception of those earnings changes due to such noncash expenses as DD&A, financial instrument fair value changes,
property impairments and deferred income tax expense. As a result, our operating cash flow increased in 2007 primarily due
to the increase in earnings as discussed in the “Results of Operations” section of this report.

During 2007 and 2006, operating cash flow was primarily used to fund our capital expenditures. Excluding the $2.0 billion

Chief acquisition in June 2006, our operating cash flow was sufficient to fund our 2007 and 2006 capital expenditures.
During 2005, operating cash flow was sufficient to fund our 2005 capital expenditures and $1.3 billion of debt repayments.

Other Sources of Cash

As needed, we utilize cash on hand and access our available credit under our credit facilities and commercial paper
program as sources of cash to supplement our operating cash flow. Additionally, we invest in highly liquid, short-term
investments to maximize our income on available cash balances. As needed, we may reduce such short-term investment
balances to further supplement our operating cash flow.

During 2007, we borrowed $1.5 billion under our unsecured revolving line of credit and reduced our short-term

investment balances by $202 million. We also received $341 million of proceeds from the sale of our Egyptian operations.
These sources of cash were used primarily to fund net commercial paper repayments, long-term debt repayments, common
stock repurchases and dividends on common and preferred stock.

During 2006, we borrowed $1.8 billion under our commercial paper program and reduced our short-term investment
balances by $106 million. These sources of cash were largely used to fund the $2.0 billion acquisition of Chief in June 2006.
Also during 2006, we supplemented operating cash flow with cash on hand, which was used to fund scheduled long-term
debt maturities, common stock repurchases and dividends on common and preferred stock.

During 2005, we generated $2.2 billion in pre-tax proceeds from sales of property and equipment. These consisted of $2.0

billion related to the sale of non-core oil and gas properties and $164 million related to the sale of non-core midstream
assets. Net of related income taxes, these proceeds were $2.0 billion. During 2005, we also reduced short-term investment
balances by $287 million. These sources of cash were used primarily to repurchase $2.3 billion of common stock.

MD&A

Capital Expenditures

Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our
midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition,
drilling or development of oil and gas properties, which totaled $5.7 billion, $6.8 billion and $3.6 billion in 2007, 2006 and
2005, respectively. The 2006 capital expenditures included $2.0 billion related to the acquisition of the Chief properties.
Excluding the effect of the Chief acquisition, the increase in such capital expenditures from 2005 to 2007 was due to
inflationary pressure driven by increased competition for field services and increased drilling activities in the Barnett Shale,
Gulf of Mexico, Carthage and Groesbeck areas of the United States. Additionally, capital expenditures also increased on our
properties in Azerbaijan where we achieved payout of certain carried interests in the last half of 2006.

Our capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas

processing plants, natural gas pipeline systems and oil pipelines. These midstream facilities exist primarily to support our oil
and gas development operations. Such expenditures were $371 million, $357 million and $121 million in 2007, 2006 and
2005, respectively. The majority of our midstream expenditures from 2005 to 2007 have related to development activities in
the Barnett Shale, the Woodford Shale in eastern Oklahoma and Jackfish in Canada.

Debt Repayments

During 2007, we repaid the $400 million 4.375% notes, which matured on October 1, 2007. Also during 2007, certain
holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common
stock prior to the debentures’ August 15, 2008 maturity date. We have the option, in lieu of delivering shares of Chevron
common stock, to pay exchanging debenture holders an amount of cash equal to the market value of Chevron common
stock. We paid $167 million in cash to debenture holders who exercised their exchange rights. This amount included the
retirement of debentures with a book value of $105 million and a $62 million reduction of the related embedded derivative
option’s balance.

During 2006, we retired the $500 million 2.75% notes and the $178 million ($200 million Canadian) 6.55% notes. We also

repaid $180 million of debt acquired in the Chief acquisition.

During 2005, we spent $0.8 billion to retire zero coupon convertible debentures due in 2020 and $400 million 6.75% notes

due in 2011 before their scheduled maturity dates. We also spent $0.4 billion to repay various notes that matured in 2005.

Repurchases of Common Stock

During the three-year period ended December 31, 2007, we repurchased 55.2 million shares at a total cost of $2.8
billion, or $51.49 per share, under various repurchase programs. During 2007, we repurchased 4.1 million shares at a cost of
$326 million, or $79.80 per share. During 2006, we repurchased 4.2 million shares at a cost of $253 million, or $59.61 per
share. During 2005, we repurchased 46.9 million shares at a cost of $2.3 billion, or $48.28 per share.

Dividends

Our common stock dividends were $249 million, $199 million and $136 million in 2007, 2006 and 2005, respectively. We

also paid $10 million of preferred stock dividends in 2007, 2006 and 2005. The increases in common stock dividends from
2005 to 2007 were primarily related to 25% and 50% increases in the quarterly dividend rate in the first quarters of 2007 and
2006, respectively. The increase from 2005 to 2006 was partially offset by a decrease in outstanding shares due to share
repurchases.

Liquidity

Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain revolving
lines 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. During 2008, another
major source of liquidity will be proceeds from the sales of our operations in West Africa. We expect the combination of
these sources of capital will be more than adequate to fund future capital expenditures, debt repayments, common stock
repurchases, and other contractual commitments as discussed later in this section.

MD&A

Operating Cash Flow

Our operating cash flow has increased approximately 16% since 2005, reaching a total of $6.2 billion in 2007. We expect
operating cash flow to continue to be our primary source of liquidity. Our operating cash flow is sensitive to many variables,
the most volatile of which is pricing of the oil, natural gas and NGLs we produce. 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.

We periodically deem it appropriate to mitigate some of the risk inherent in oil and natural gas prices. Accordingly, we
have utilized price collars to set minimum and maximum prices on a portion of our production. We have also utilized various
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. Based on contracts in place as of February 15, 2008, in 2008 approximately 64% of our estimated
natural gas production and 12% of our estimated oil production are subject to either price collars, swaps or fixed-price
contracts. The key terms of these contracts are summarized in the Quantitative and Qualitative Disclosures about Market Risk
section of this book.

Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant
commodity price increases, as experienced in recent years, can lead to an increase in drilling and development activities. As a
result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on
our cash flow.

Credit Availability

We have two revolving lines of credit and a commercial paper program, which we can access to provide liquidity. At

December 31, 2007, our total available borrowing capacity was $1.3 billion.

Our $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) matures on April 7,
2012, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April 7
anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval
of the lenders.

The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million.
Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods
of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate.
As of December 31, 2007, there were $1.4 billion of borrowings under the Senior Credit Facility at an average rate of 5.27%.

On August 7, 2007, we established a new $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility (the

“Short-Term Facility”). This facility provides us with provisional interim liquidity until we receive the proceeds from
divestitures of assets in West Africa. The Short-Term Facility was also used to support an increase in our commercial paper
program from $2 billion to $3.5 billion.

The Short-Term Facility matures on August 5, 2008. At that time, all amounts outstanding will be due and payable unless

the maturity is extended. Prior to August 5, 2008, we have the option to convert any outstanding principal amount of loans
under the Short-Term Facility to a term loan, which will be repayable in a single payment on August 4, 2009.

Amounts borrowed under the Short-Term Facility bear interest at various fixed rate options for periods of up to 12
months. Such rates are generally less than the prime rate. We may also elect to borrow at the prime rate. As of December 31,
2007, there were no borrowings under the Short-Term Facility.

We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial

paper program may not exceed $3.5 billion. Also, any borrowings under the commercial paper program reduce available
capacity under the Senior Credit Facility or the Short-Term Facility on a dollar-for-dollar basis. Commercial paper debt
generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears 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,
LIBOR, or the money market rate as found on the commercial paper market. As of December 31, 2007, we had $1.0 billion of
commercial paper debt outstanding at an average rate of 5.07%.

The Senior Credit Facility and Short-Term Facility contain only one material financial covenant. This covenant requires
our ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total
funded debt and total capitalization that include adjustments to the respective amounts reported in our consolidated
financial statements. As defined in the agreement, total funded debt excludes the debentures that are exchangeable into
shares of Chevron Corporation common stock. Also, total capitalization is adjusted to add back noncash financial
writedowns such as full cost ceiling impairments or goodwill impairments. As of December 31, 2007, we were in
compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2007, as calculated pursuant to the terms
of the agreement, was 23.8%.

MD&A

Our access to funds from the Senior Credit Facility and Short-Term Facility is not restricted under any “material adverse
effect” 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 credit facilities
include covenants that require us to report a condition or event having a material adverse effect, the obligation of the
banks to fund the credit facilities is not conditioned on the absence of a material adverse effect.

Debt Ratings

We receive debt ratings from the major ratings agencies in the United States. In determining our debt ratings, 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. Our current debt ratings are BBB with a positive
outlook by Standard & Poor’s, Baa1 with a stable outlook by Moody’s and BBB with a positive 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. Our cost of borrowing under our Senior Credit Facility and Short-Term Facility is
predicated on our 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 credit facilities. Under the terms of the
Senior Credit Facility and the Short-Term Facility, a one-notch downgrade would increase the fully-drawn borrowing costs
for the credit facilities from LIBOR plus 35 basis points to a new rate of LIBOR plus 45 basis points. A ratings downgrade
could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2007, we
were not aware of any potential ratings downgrades being contemplated by the rating agencies.

Capital Expenditures

In February 2008, we provided guidance for our 2008 capital expenditures, which are expected to range from $6.6
billion to $7.0 billion. This represents the largest planned use of our 2008 operating cash flow, with the high end of the
range being 13% higher than our 2007 capital expenditures. 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 2008 capital expenditures until later periods, or accelerate capital expenditures planned
for periods beyond 2008 to achieve the desired balance between sources and uses of liquidity. Based upon current oil and
natural gas price expectations for 2008 and the commodity price collars, swaps and fixed-price contracts we have in place,
we anticipate having adequate capital resources to fund our 2008 capital expenditures.

Common Stock Repurchase Programs

We have an ongoing, annual stock repurchase program to minimize dilution resulting from restricted stock issued to,

and options exercised by, employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million
shares or a cost of $422 million, whichever amount is reached first.

In anticipation of the completion of our West African divestitures, our Board of Directors has approved a separate

program to repurchase up to 50 million shares. This program expires on December 31, 2009.

Exchangeable Debentures

As of December 31, 2007, our outstanding debt included debentures that are exchangeable for Chevron common
stock. These debentures have a scheduled maturity date of August 15, 2008. Although these debentures are now due
within one year, we continue to classify this debt as long-term because we have the intent and ability to refinance these
debentures on a long-term basis with the available capacity under our existing credit facilities or other long-term financing
arrangements.

Canadian Royalties

On October 25, 2007, the Alberta government proposed increases to the royalty rates on oil and natural gas

production beginning in 2009. We believe this proposal would reduce future earnings and cash flows from our oil and gas
properties located in Alberta. Additionally, assuming all other factors are equal, higher royalty rates would likely result in
lower levels of capital investment in Alberta relative to our other areas of operation. However, the magnitude of the
potential impact, which will depend on the final form of enacted legislation and other factors that impact the relative
expected economic returns of capital projects, cannot be reasonably estimated at this time.

MD&A

Contractual Obligations

A summary of our contractual obligations as of December 31, 2007, is provided in the following table.

Long-term debt (1)
Interest expense (2)

Drilling and facility obligations (3)
Asset retirement obligations (4)
Firm transportation agreements (5)
Lease obligations (6)
Other

Total

Payments Due by Period

Total

Less Than
1 Year

1-3 Years

3-5 Years

(In millions)

More Than
5 Years

7,908
5,412
3,935
1,362
1,040
578
134
20,369

1,004
508
983
91
170
104
71
2,931

177
708
1,254
138
329
166
59
2,831

4,202
545
747
128
234
125
4
5,985

2,525
3,651
951
1,005
307
183
—
8,622

(1)

(2)

Except for our debentures exchangeable into Chevron common stock, long-term debt amounts represent scheduled maturities of our debt obligations at December 31, 2007, excluding $20 million of net
premiums included in the carrying value of debt. Although the maturity date of the exchangeable debentures is August 2008, we have the ability and intent to refinance these borrowings under our credit
facilities or other long-term arrangements. Therefore, the $652 million face value of outstanding exchangeable debentures is included in the “3-5 Years” amount. As of December 31, 2007, we owned
approximately 14.2 million shares of Chevron common stock. The majority of these shares are held for possible exchange when holders elect to exchange their debentures.
The “Less than 1 Year” amount represents our short-term commercial paper borrowings. The “3-5 Years” amount includes $1.4 billion of borrowings against our Senior Credit Facility. We intend to use the
proceeds from the sales of West African assets to repay our outstanding commercial paper and credit facility borrowings. Also, $198 million of letters of credit that have been issued by commercial banks
on our behalf are excluded from the table. The majority of these letters of credit, if funded, would become borrowings under our credit facilities. Most of these letters of credit have been granted by
financial institutions to support our international and Canadian drilling commitments.
Interest expense amounts represent the scheduled fixed-rate and variable-rate cash payments related to our debt. Interest on our variable-rate debt was estimated based upon expected future interest
rates as of December 31, 2007.

(3) Drilling and facility obligations represent contractual agreements with third party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and
facilities construction. Included in the $3.9 billion total is $2.4 billion that relates to long-term contracts for three deepwater drilling rigs and certain other contracts for onshore drilling and facility
obligations in which drilling or facilities construction has not commenced. The $2.4 billion represents the gross commitment under these contracts. Our ultimate payment for these commitments will be
reduced by the amounts billed to our working interest partners. Payments for these commitments, net of amounts billed to partners, will be capitalized as a component of oil and gas properties. Also
included in the $3.9 billion total is $144 million of drilling and facility obligations related to our discontinued operations.

(4) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31,

(5)

(6)

2007 balance sheet. Included in the $1.4 billion total is $44 million of asset retirement obligations related to our discontinued operations.
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 production to market. We expect to have sufficient production to utilize the majority of these transportation services.
Lease obligations consist of operating leases for office space and equipment, an offshore platform spar and FPSO’s. Office and equipment leases represent non-cancelable leases for office space and
equipment used in our daily operations.
We have an offshore platform spar that is being used in the development of the Nansen field in the Gulf of Mexico. This spar is subject to a 20-year lease and contains various options whereby we may
purchase the lessors’ interests in the spars. We have guaranteed that the spar will have a residual value at the end of the term equal to at least 10% of the fair value of the spar at the inception of the
lease. The total guaranteed value is $14 million in 2022. However, such amount may be reduced under the terms of the lease agreements. In 2005, we sold our interests in the Boomvang field in the Gulf
of Mexico, which has a spar lease with terms similar to those of the Nansen lease. As a result of the sale, we are subleasing the Boomvang Spar. The table above does not include any amounts related to
the Boomvang spar lease. However, if the sublessee were to default on its obligation, we would continue to be obligated to pay the periodic lease payments and any guaranteed value required at the end
of the term.
We also lease two FPSO’s that are being used in the Panyu project offshore China and the Polvo project offshore Brazil. The Panyu FPSO lease term expires in September 2009. The Polvo FPSO lease term
expires in 2014.

Pension Funding and Estimates

Funded Status. As compared to the “projected benefit obligation,” our qualified and nonqualified defined benefit plans
were underfunded by $230 million and $178 million at December 31, 2007 and 2006, respectively. A detailed reconciliation
of the 2007 changes to our underfunded status is included in Note 6 to the accompanying consolidated financial statements.
Of the $230 million underfunded status at the end of 2007, $198 million is attributable to various nonqualified defined
benefit plans that have no plan assets. However, we have established certain trusts to fund the benefit obligations of such
nonqualified plans. As of December 31, 2007, these trusts had investments with a fair value of $59 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 $62 million

at December 31, 2007. 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 and payments made to participants. 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 2008, we anticipate the accumulated
benefit obligation will remain fully funded without contributing to our qualified defined benefit plans. Therefore, we don’t
expect to contribute to the plans during 2008.

Pension Estimate Assumptions. Our 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 $41 million, $31 million and $26 million in 2007, 2006 and 2005, respectively. We estimate
that our pension expense will approximate $61 million in 2008.

MD&A

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

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

We assumed that our plan assets would generate a long-term weighted average rate of return of 8.40% at both

December 31, 2007 and 2006. 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 our 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 expect
our long-term asset allocation on average to 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 8.40% to 7.40%) would increase the expected 2008 pension expense by $6 million.
We discounted our future pension obligations using a weighted average rate of 6.22% and 5.72% at December 31, 2007
and 2006, respectively. The discount rate is determined at the end of each year based on the rate at which obligations could
be effectively settled, considering the expected timing of future cash flows related to the plans. 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 6.22% to 5.97%) would increase our pension liability at December 31, 2007, by $28 million, and
increase estimated 2008 pension expense by $4 million.

At December 31, 2007, we had actuarial losses of $208 million, which will be recognized as a component of pension

expense in future years. These losses are primarily due to reductions in the discount rate since 2001 and increases in
participant wages. We estimate that approximately $14 million and $12 million of the unrecognized actuarial losses will be
included in pension expense in 2008 and 2009, respectively. The $14 million estimated to be recognized in 2008 is a
component of the total estimated 2008 pension expense of $61 million referred to earlier in this section.

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

On August 17, 2006, the Pension Protection Act was signed into law. Beginning in 2008, this act will cause extensive
changes in the determination of both the minimum required contribution and the maximum tax deductible limit. Because
the new required contribution will approximate our current policy of fully funding the accumulated benefit obligation, the
changes are not expected to have a significant impact on future cash flows.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 8 of the accompanying consolidated financial

statements.

Critical Accounting Policies and Estimates

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. Actual amounts could differ from these estimates, and changes in
these estimates are recorded when known.

The critical accounting policies used by management in the preparation of our consolidated financial statements are
those that are important both to the presentation of our financial condition and results of operations and require significant
judgments by management with regard to estimates used. Our critical accounting policies and significant judgments and
estimates related to those policies are described below. We have reviewed these critical accounting policies with the Audit
Committee of the Board of Directors.

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Full Cost Ceiling Calculations

Policy Description

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 our net book value of oil and gas properties, less related
deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense, except as
discussed in the following paragraph. The ceiling limitation is imposed separately for each country in which we have oil and
gas properties.

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

to levels such that the ceiling would exceed the costs to be recovered, a writedown otherwise indicated at the end of the
quarter is not required to be recorded. A writedown indicated at the end of a quarter is also not required if the value of
additional reserves proved up on properties after the end of the quarter but prior to the publishing of the financial
statements would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end
of the quarter. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and
gas prices may have increased the ceiling applicable to the subsequent period.

Judgments and Assumptions

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 or audited by outside petroleum
consultants, while other reserve estimates are prepared by our engineers. See Note 15 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 1% 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 a 10% discount factor be used and 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 our 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 derivative contracts in place that qualify for hedge accounting treatment. This adjustment
requires little judgment as the end-of-period price is adjusted using the contract prices for such hedges. None of our
outstanding derivative contracts at December 31, 2007 qualified for hedge accounting treatment.

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 volatile. On any particular day at the end of a quarter, prices 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.

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Derivative Financial Instruments

Policy Description

The majority of our historical derivative instruments have consisted of commodity financial instruments used to manage
our cash flow exposure to oil and gas price volatility. We have also entered into interest rate swaps to manage our exposure
to interest rate volatility. The interest rate swaps mitigate either the cash flow effects of interest rate fluctuations on interest
expense for variable-rate debt instruments, or the fair value effects of interest rate fluctuations on fixed-rate debt. We also
have an embedded option derivative related to the fair value of our debentures exchangeable into shares of Chevron
Corporation common stock.

All derivatives are recognized at their current fair value on our balance sheet. Changes in the fair value of derivative
financial instruments are recorded in the statement of operations unless specific hedge accounting criteria are met. If such
criteria are met for cash flow hedges, the effective portion of the change in the fair value is recorded directly to accumulated
other comprehensive income, a component of stockholders’ equity, until the hedged transaction occurs. The ineffective
portion of the change in fair value is recorded in the statement of operations. If hedge accounting criteria are met for fair
value hedges, the change in the fair value is recorded in the statement of operations with an offsetting amount recorded for
the change in fair value of the hedged item.

A derivative financial instrument qualifies for hedge accounting treatment if we designate the instrument as such on the

date the derivative contract is entered into or the date of an acquisition or business combination that includes derivative
contracts. Additionally, we must document the relationship between the hedging instrument and hedged item, as well as the
risk-management objective and strategy for undertaking the instrument. We must also assess, both at the instrument’s
inception and on an ongoing basis, whether the derivative is highly effective in offsetting the change in cash flow of the
hedged item.

For the derivative financial instruments we have executed in 2006, 2007 and to date in 2008, we have chosen to not meet

the necessary criteria to qualify such instruments for hedge accounting.

Judgments and Assumptions

The estimates of the fair values of our commodity derivative instruments require substantial judgment. For these
instruments, 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 our other derivative instruments 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 instruments qualify for hedge accounting treatment. Changes in the fair values of
derivatives that do not qualify for hedge accounting treatment can have a significant impact on our results of operations, but
generally will not impact our liquidity or capital resources. Settlements of derivative instruments, regardless of whether they
qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices
are higher than the price of the derivative instruments, 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 this report.

Business Combinations

Policy Description

From our beginning as a public company in 1988 through 2003, we grew substantially 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.

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Judgments and Assumptions

There are various assumptions we make 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. Our
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 analysis. Forecasts of future prices from independent third parties are
noted when we make our 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 our cost of capital.
We also apply these same general principles to estimate 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 our 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 we assume in the acquisition, and this debt must be recorded at the estimated fair value as if we had issued such debt.
However, significant judgment 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 acquisition of Mitchell Energy & Development Corp., our 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 we also acquired 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, we perform other quantitative analyses to support the indicated

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

In a comparable 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. We compare these comparable company multiples
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. We compare these comparable
transaction multiples to the proposed business combination transaction multiples for reasonableness.

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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. We use this information
to determine the mean and median premiums paid and compare 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 our 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 our price forecast that was used to originally determine fair value. A full cost
ceiling writedown would have no effect on our liquidity or capital resources in that period because it is a noncash charge, but
it would adversely affect results of operations. As discussed in “Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Capital Resources, Uses and Liquidity,” 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, our annual revisions to our reserve estimates have averaged
approximately 1%. 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

Policy Description

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.

Judgments and Assumptions

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 our 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 our reserve estimates previously set forth.

Recently Issued Accounting Standards Not Yet Adopted

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting

Standards No. 141(R), Business Combinations, which replaces Statement No. 141. Statement No. 141(R) retains the
fundamental requirements of Statement No. 141 that an acquirer be identified and the acquisition method of accounting
(previously called the purchase method) be used for all business combinations. Statement No. 141(R)’s scope is broader than
that of Statement No. 141, which applied only to business combinations in which control was obtained by transferring
consideration. By applying the acquisition method to all transactions and other events in which one entity obtains control
over one or more other businesses, Statement No. 141(R) improves the comparability of the information about business
combinations provided in financial reports. Statement No. 141(R) establishes principles and requirements for how an
acquirer recognizes and measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the
acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business combinations for which

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the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15,
2008. We will evaluate how the new requirements of Statement No. 141(R) would impact any business combinations
completed in 2009 or thereafter.

In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in

Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. A noncontrolling interest,
sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a
parent. Statement No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a subsidiary must be reported
as a component of consolidated equity separate from the parent’s equity. Additionally, the amounts of consolidated net
income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the
income statement. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier
adoption is prohibited. We do not expect the adoption of Statement No. 160 to have a material impact on our financial
statements and related disclosures.

2008 Estimates

The forward-looking statements provided in this discussion are based on our examination of historical operating trends,

the information that was used to prepare the December 31, 2007 reserve reports and other data in our possession or
available from third parties. These forward-looking statements were prepared assuming demand, curtailment, producibility
and general market conditions for our oil, natural gas and NGLs during 2008 will be substantially similar to those of 2007,
unless otherwise noted. We make reference to the “Disclosure Regarding Forward-Looking Statements” at the beginning of
this report. Amounts related to Canadian operations have been converted to U.S. dollars using a projected average 2008
exchange rate of $0.98 U.S. dollar to $1.00 Canadian dollar.

In January 2007, we announced our intent to divest our West African oil and gas assets and terminate our operations in

West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region. In November 2007, we
announced an agreement to sell our operations in Gabon for $205.5 million. We are finalizing purchase and sales agreements
and obtaining the necessary partner and government approvals for the remaining properties in this divestiture package. We
are optimistic we can complete these sales during the first half of 2008.

All West African related revenues, expenses and capital will be reported as discontinued operations in our 2008 financial

statements. Accordingly, all forward-looking estimates in the following discussion exclude amounts related to our
operations in West Africa, unless otherwise noted.

Though we have completed several major property acquisitions and dispositions in recent years, these transactions are

opportunity driven. Thus, the following forward-looking estimates do not include any financial and operating effects of
potential property acquisitions or divestitures that may occur during 2008, except for West Africa as previously discussed.

Oil, Gas and NGL Production

Set forth below are our estimates of oil, gas and NGL production for 2008. We estimate that our combined 2008 oil, gas

and NGL production will total approximately 240 to 247 MMBoe. Of this total, approximately 92% is estimated to be
produced from reserves classified as “proved” at December 31, 2007. The following estimates for oil, gas and NGL
production are calculated at the midpoint of the estimated range for total production.

Oil
(MMBbls)

12
8
23
23
66

gas
(Bcf)

626
68
198
2
894

NgLs
(MMBbls)

Total
(MMBoe)

23
1
4
—
28

140
20
60
23
243

U.S. Onshore
U.S. Offshore
Canada

International
Total

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Oil and Gas Prices

Oil and Gas Operating Area Prices

We expect our 2008 average prices for the oil and gas production from each of our operating areas to differ from the
NYMEX price as set forth in the following table. These expected ranges are exclusive of the anticipated effects of the oil and
gas financial contracts presented in the “Commodity Price Risk Management” section below.

The NYMEX price for oil is the monthly average of settled prices on each trading day for benchmark West Texas
Intermediate crude oil delivered at Cushing, Oklahoma. The NYMEX price for gas is determined to be the first-of-month
south Louisiana Henry Hub price index as published monthly in Inside FERC.

U.S. Onshore
U.S. Offshore
Canada

International

Commodity Price Risk Management

Expected Range of Prices
as a % of NYMEX Price

Oil

gas

85% to 95%
90% to 100%
55% to 65%
85% to 95%

80% to 90%
95% to 105%
85% to 95%
83% to 93%

From time to time, we enter into NYMEX-related financial commodity collar and price swap contracts. Such contracts
are used to manage the inherent uncertainty of future revenues due to oil and gas price volatility. Although these financial
contracts do not relate to specific production from our operating areas, they will affect our overall revenues and average
realized oil and gas prices in 2008.

The key terms of our 2008 oil and gas financial collar and price swap contracts are presented in the following tables. The

tables include contracts entered into as of February 15, 2008.

Period

First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2008 Average

Period

First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2008 Average

Oil Financial Contracts

Price Collar Contracts

Floor Price

Ceiling Price

Volume
(Bbls/d)

21,011
22,000
22,000
22,000
21,754

Floor
Price
($/Bbl)

$70.00
$70.00
$70.00
$70.00
$70.00

Ceiling
Range
($/Bbl)

$132.50 - 148.00
$132.50 - 148.00
$132.50 - 148.00
$132.50 - 148.00
$132.50 - 148.00

weighted
Average
Ceiling Price
($/Bbl)

$140.31
$140.20
$140.20
$140.20
$140.23

gas Financial Contracts

Price Collar Contracts

Floor Price

Floor
Price
($/MMBtu)

Ceiling Price

Ceiling
Range
($/MMBtu)

weighted
Average
Ceiling Price
($/MMBtu)

$7.50
$7.50
$7.50
$7.50
$7.50

$9.00 - 10.25
$9.00 - 10.25
$9.00 - 10.25
$9.00 - 10.25
$9.00 - 10.25

$9.43
$9.43
$9.43
$9.43
$9.43

Volume
(MMBtu/d)

634,011
1,080,000
1,080,000
1,080,000
969,112

Price Swap Contracts

Volume
(MMBtu/d)

364,670
620,000
620,000
620,000
556,516

weighted
Average
Price
($/MMBtu)

$8.23
$8.24
$8.24
$8.24
$8.24

To the extent that monthly NYMEX prices in 2008 differ from those established by the gas price swaps, or are outside of
the ranges established by the oil and natural gas collars, we and the counterparties to the contracts will settle the difference.
Such settlements will either increase or decrease our oil and gas revenues for the period. Also, we will mark-to-market the
contracts based on their fair values throughout 2008. Changes in the contracts’ fair values will also be recorded as increases
or decreases to our oil and gas revenues. The expected ranges of our realized oil and gas prices as a percentage of NYMEX
prices, which are presented earlier in this document, do not include any estimates of the impact on our oil and gas prices
from monthly settlements or changes in the fair values of our oil and gas price swaps and collars.

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Marketing and Midstream Revenues and Expenses

Marketing and midstream revenues and expenses are derived primarily from our gas processing plants and gas pipeline

systems. 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 gas and NGLs, provisions of contractual agreements and the amount of repair and maintenance activity
required to maintain anticipated processing levels and pipeline throughput volumes.

These factors increase the uncertainty inherent in estimating future marketing and midstream revenues and expenses.

Given these uncertainties, we estimate that our 2008 marketing and midstream operating profit will be between $510
million and $550 million. We estimate that marketing and midstream revenues will be between $1.61 billion and $2.01 billion,
and marketing and midstream expenses will be between $1.10 billion and $1.46 billion.

Production and Operating Expenses

Our 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 the property base, changes in the general price level of services and materials that are used in the operation of the
properties, the amount of repair and workover activity required and changes in production tax rates. Oil, 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 expect that our 2008 lease operating expenses will be between $2.17 billion to $2.24

billion. Additionally, we estimate that our production taxes for 2008 will be between 3.5% and 4.0% of total oil, gas and NGL
revenues, excluding the effect on revenues from financial collars and price swap contracts upon which production taxes are
not assessed.

Depreciation, Depletion and Amortization (“DD&A”)

Our 2008 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 2008 compared to the costs incurred for
such efforts, and the revisions to our year-end 2007 reserve estimates that, based on prior experience, are likely to be made
during 2008.

Given these uncertainties, we estimate that our oil and gas property-related DD&A rate will be between $12.75 per Boe
and $13.25 per Boe. Based on these DD&A rates and the production estimates set forth earlier, oil and gas property related
DD&A expense for 2008 is expected to be between $3.09 billion and $3.20 billion.

Additionally, we expect that our depreciation and amortization expense related to non-oil and gas property fixed assets

will total between $260 million and $270 million in 2008.

Accretion of Asset Retirement Obligation

Accretion of asset retirement obligation in 2008 is expected to be between $75 million and $85 million.

General and Administrative Expenses (“G&A”)

Our G&A includes employee compensation and benefits costs and the costs of many different goods and services used in

support of our business. G&A varies with the level of our operating activities and the related staffing and professional
services requirements. In addition, employee compensation and benefits costs vary due to various market factors that affect
the level and type of compensation and benefits offered to employees. Also, goods and services are subject to general price
level increases or decreases. Therefore, significant variances in any of these factors from current expectations could cause
actual G&A to vary materially from the estimate.

Given these limitations, we estimate our G&A for 2008 will be between $590 million and $610 million. This estimate
includes approximately $90 million of non-cash, share-based compensation, net of related capitalization in accordance with
the full cost method of accounting for oil and gas properties.

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Reduction of Carrying Value of Oil and Gas Properties

We follow the full cost method of accounting for our oil and gas properties described in “Management’s Discussion and

Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates.” Reductions to the
carrying value of our oil and gas properties are largely dependent on the success of drilling results and oil and natural gas
prices at the end of our quarterly reporting periods. Due to the uncertain nature of future drilling efforts and oil and natural
gas prices, we are not able to predict whether we will incur such reductions in 2008.

Interest Expense

Future interest rates and debt outstanding have a significant effect on our interest expense. We can only marginally
influence the prices we will receive in 2008 from sales of oil, gas and NGLs and the resulting cash flow. Likewise, we can only
marginally influence the timing of the closing of our West African divestitures and the attendant cash receipts. These factors
increase the margin of error inherent in estimating future outstanding debt balances and related interest expense. Other
factors that affect outstanding debt balances and related interest expense, such as the amount and timing of capital
expenditures are generally within our control.

Based on the information related to interest expense set forth below, we expect our 2008 interest expense to be

between $340 million and $350 million. This estimate assumes no material changes in prevailing interest rates. This estimate
also assumes no material changes in our expected level of indebtedness, except for an assumption that our commercial
paper and credit facility borrowings will decrease in conjunction with the planned divestiture of our West African operations,
which we are optimistic will be completed by the end of the second quarter of 2008.

The interest expense in 2008 related to our fixed-rate debt, including net accretion of related discounts, will be

approximately $385 million. This fixed-rate debt removes the uncertainty of future interest rates from some, but not all, of
our long-term debt.

Our floating rate debt is comprised of variable-rate commercial paper and borrowings against our senior credit facility.

Our floating rate debt is summarized in the following table:

Debt Instrument

Commercial paper
Senior credit facility

Notional Amount (1)
(In millions)

$
$

1,004
1,450

Floating Rate

Various (2)
Various (3)

(1)
(2)

(3)

Represents outstanding balance as of December 31, 2007.
The interest rate is based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market. As of December 31, 2007, the average rate
on the outstanding balance was 5.07%.
The borrowings under the senior credit facility bear interest at various fixed rate options for periods of up to twelve months and are generally less than the prime rate. As of December 31, 2007, the
average rate on the outstanding balance was 5.27%.

Based on estimates of future LIBOR and prime rates as of December 31, 2007, interest expense on floating rate debt,

including net amortization of premiums, is expected to total between $70 million and $80 million in 2008.

Our interest expense totals include payments of facility and agency fees, amortization of debt issuance costs 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 2008 interest expense. Also, we expect to capitalize between $120 million and $130 million of
interest during 2008, including amounts related to our discontinued operations.

Other Income

We estimate that our other income in 2008 will be between $55 million and $75 million.
As of the end of 2007, we had received insurance claim settlements related to the 2005 hurricanes that were $150 million

in excess of amounts incurred to repair related damages. None of this $150 million excess has been recognized as income,
pending the resolution of the amount of future necessary repairs and the settlement of certain claims that have been filed
with secondary insurers. Based on the most recent estimates of our costs for repairs, we believe that some amount will
ultimately be recorded as other income. However, the timing and amount that would be recorded as other income are
uncertain. Therefore, the 2008 estimate for other income above does not include any amount related to hurricane proceeds.

MD&A

Income Taxes

Our financial income tax rate in 2008 will vary materially depending on the actual amount of financial pre-tax earnings.
The tax rate for 2008 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 2008 income tax expense regardless of the level of pre-tax earnings that are
produced.

Given the uncertainty of pre-tax earnings, we expect that our consolidated financial income tax rate in 2008 will be

between 20% and 40%. The current income tax rate is expected to be between 10% and 15%. The deferred income tax rate is
expected to be between 10% and 25%. 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 2008 financial income tax rates.

Discontinued Operations

As previously discussed, in November 2007, we announced an agreement to sell our operations in Gabon for $205.5
million. We are finalizing purchase and sales agreements and obtaining the necessary partner and government approvals for
the remaining properties in the West African divestiture package. We are optimistic we can complete these sales during the
first half of 2008.

The following table presents the 2008 estimates for production, production and operating expenses and capital
expenditures associated with these discontinued operations. These estimates include amounts related to all assets in the
West African divestiture package for the first half of 2008. Pursuant to accounting rules for discontinued operations, the
West African assets are not subject to DD&A during 2008.

Oil production (MMBbls)
Gas production (Bcf)
Total production (MMBoe)

Production and operating expenses (In millions)
Capital expenditures (In millions)

Year 2008 Potential Capital Resources, uses and Liquidity

Capital Expenditures

4
3
4

$30
$50

Though we have 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.

Our capital expenditures budget is based on an expected range of future oil, gas and NGL prices, as well as the expected

costs of the capital additions. Should actual prices received differ materially from our price expectations for our future
production, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2008 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 above, the following table shows expected drilling, development and facilities

expenditures by geographic area. Development capital includes development activity related to reserves classified as proved
as of year-end 2007 and drilling activity in areas that do 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.

u.S.
Onshore

u.S.
Offshore

Canada

(In millions)

International

Total

Development capital
Exploration capital

Total

$ 2,870 - 3,020
$ 310 - 330
$ 3,180 - 3,350

$ 490 - 520
$ 320 - 340
$ 810 - 860

$ 1,070 - 1,120
$ 135 - 145
$ 1,205 - 1,265

$ 205 - 220
$ 185 - 205
$ 390 - 425

$ 4,635 - 4,880
$ 950 - 1,020
$ 5,585 - 5,900

MD&A

In addition to the above expenditures for drilling, development and facilities, we expect to spend between $325 million to
$375 million on our marketing and midstream assets, which primarily include our oil pipelines, gas processing plants, and gas
pipeline systems. We expect to capitalize between $335 million and $345 million of G&A expenses in accordance with the full
cost method of accounting and to capitalize between $110 million and $120 million of interest. We also expect to pay
between $70 million and $80 million for plugging and abandonment charges, and to spend between $130 million and $140
million for other non-oil and gas property fixed assets.

Other Cash Uses

Our management expects the policy of paying a quarterly common stock dividend to continue. With the current $0.14
per share quarterly dividend rate and 444 million shares of common stock outstanding as of December 31, 2007, dividends
are expected to approximate $250 million. Also, we have $150 million of 6.49% cumulative preferred stock upon which we
will pay $10 million of dividends in 2008.

Capital Resources and Liquidity

Our estimated 2008 cash uses, including our drilling and development activities, retirement of debt and repurchase of

common stock, are expected to be funded primarily through a combination of existing cash and short-term investments,
operating cash flow and proceeds from the sale of our assets in West Africa. Any remaining cash uses could be funded by
increasing our borrowings under our commercial paper program or with borrowings from the available capacity under our
credit facilities, which was approximately $1.3 billion at December 31, 2007. The amount of operating cash flow to be
generated during 2008 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 2008. 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.

Our $372 million of short-term investments as of December 31, 2007 consisted entirely of auction rate securities
collateralized by student loans which are substantially guaranteed by the United States government. Subsequent to
December 31, 2007, we have reduced our auction rate securities holdings to $153 million. However, beginning on February
8, 2008, we experienced difficulty selling additional securities due to the failure of the auction mechanism which provides
liquidity to these securities. The securities for which auctions have failed will continue to accrue interest and be auctioned
every 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Accordingly, there may be
no effective mechanism for selling these securities, and the securities we own may become long-term investments. At this
time, we do not believe such securities are impaired or that the failure of the auction mechanism will have a material impact
on our liquidity.

Quantitative and Qualitative Disclosures about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information
about our 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 we view and manage our 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.

We periodically enter into financial hedging activities with respect to a portion of our oil and gas production through
various financial transactions that 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, we will settle the difference with the counterparty to the
collars. These financial hedging activities are intended to support oil and gas prices at targeted levels and to manage our
exposure to oil and gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.

MD&A

Based on natural gas contracts in place as of February 15, 2008 we have approximately 1.6 Bcf per day of gas production
in 2008 that is subject to either price swaps or collars or fixed-price contracts. This amount represents approximately 64% of
our estimated 2008 gas production, or 40% of our total Boe production. All of these price swap and collar contracts expire
December 31, 2008. As of February 15, 2008, we do not have any gas price swaps or collars extending beyond 2008.
However, our fixed-price physical delivery contracts extend through 2011. These physical delivery contracts relate to our
Canadian natural gas production and range from six Bcf to 14 Bcf per year. These physical delivery contracts are not
expected to have a material effect on our realized gas prices from 2009 through 2011.

The key terms of our 2008 gas financial collar and price swap contracts are presented in the following table.

Period

First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2008 Average

gas Financial Contracts

Price Collar Contracts

Floor Price

Floor
Price
($/MMBtu)

Ceiling Price

Ceiling
Range
($/MMBtu)

weighted
Average
Ceiling Price
($/MMBtu)

$7.50
$7.50
$7.50
$7.50
$7.50

$9.00 - 10.25
$9.00 - 10.25
$9.00 - 10.25
$9.00 - 10.25
$9.00 - 10.25

$9.43
$9.43
$9.43
$9.43
$9.43

Volume
(MMBtu/d)

634,011
1,080,000
1,080,000
1,080,000
969,112

Price Swap Contracts

Volume
(MMBtu/d)

364,670
620,000
620,000
620,000
556,516

weighted
Average
Price
($/MMBtu)

$8.23
$8.24
$8.24
$8.24
$8.24

Based on oil contracts in place as of February 15, 2008 we have approximately 22,000 Bbls per day of oil production in
2008 that is subject to price collars. This amount represents approximately 12% of our estimated 2008 oil production, or 3%
of our total Boe production. All of these price collar contracts expire December 31, 2008. As of February 15, 2008, we do not
have any oil price swaps or collars extending beyond 2008.

The key terms of our 2008 oil financial collar contracts are presented in the following table.

Period

First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2008 Average

Interest Rate Risk

Oil Financial Contracts

Price Collar Contracts

Floor Price

Ceiling Price

Volume
(Bbls/d)

21,011
22,000
22,000
22,000
21,754

Floor
Price
($/Bbl)

$70.00
$70.00
$70.00
$70.00
$70.00

Ceiling
Range
($/Bbl)

$132.50 - 148.00
$132.50 - 148.00
$132.50 - 148.00
$132.50 - 148.00
$132.50 - 148.00

weighted
Average
Ceiling Price
($/Bbl)

$140.31
$140.20
$140.20
$140.20
$140.23

At December 31, 2007, we had debt outstanding of $7.9 billion. Of this amount, $5.5 billion, or 69%, bears interest at
fixed rates averaging 7.3%. Additionally, we had $1.0 billion of outstanding commercial paper and $1.4 billion of credit facility
borrowings bearing interest at floating rates, which averaged 5.07% and 5.27%, respectively. At the end of 2007 and as of
February 15, 2008, we did not have any interest rate hedging instruments.

Foreign Currency Risk

Our net assets, net earnings and cash flows from our 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. A 10% unfavorable change in the Canadian-
to-U.S. dollar exchange rate would not materially impact our December 31, 2007 balance sheet.

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,
2007 and 2006, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for
each of the years in the three-year period ended December 31, 2007. We also have audited Devon Energy Corporation’s internal control
over financial reporting as of December 31, 2007, 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 these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of
the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report. Our
responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over
financial reporting 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 audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our
audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the
overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and
operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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, 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, 2007 and 2006, and the results of its operations and its cash flows for
each of the years in the three-year period ended December 31, 2007, in conformity with accounting principles generally accepted in the
United States of America. Also in our opinion, Devon Energy Corporation maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2007, based on control criteria established in Internal Control - Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission.

As described in note 1 to the consolidated financial statements, as of January 1, 2007, the Company adopted Statement of Financial
Accounting Standards No. 157, Fair Value Measurements, Statement of Financial Accounting Standards No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, and FASB Interpretation No. 48 Accounting
for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109. During 2007, the Company adopted the measurement date
provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other
Postretirement Plans – an Amendment of FASB Statements No. 87, 88, 106, and 132(R). Additionally, as of January 1, 2006, the Company
adopted Statements of Financial Accounting Standards No. 123(R), Share-Based Payment, and as of December 31, 2006, the Company
adopted the balance sheet recognition provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for
Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106, and 132 (R).

Oklahoma City, Oklahoma
February 26, 2008

Consolidated Balance Sheets

DEVON ENERGY CORPORATION AND SUBSIDIARIES

ASSETS
Current assets:
Cash and cash equivalents
Short-term investments, at fair value
Accounts receivable
Deferred income taxes
Current assets held for sale
Other current assets
Total current assets

Property and equipment, at cost, based on the full cost method of
accounting for oil and gas properties ($3,417 and $3,293 excluded
from amortization in 2007 and 2006, respectively)
Less accumulated depreciation, depletion and amortization

Investment in Chevron Corporation common stock, at fair value
Goodwill
Assets held for sale
Other assets

Total assets

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable – trade
Revenues and royalties due to others

Income taxes payable

Short-term debt
Accrued interest payable
Current portion of asset retirement obligation, at fair value
Current liabilities associated with assets held for sale
Accrued expenses and other current liabilities

Total current liabilities

Debentures exchangeable into shares of Chevron Corporation common stock
Other long-term debt
Financial instruments, at fair value
Asset retirement obligation, at fair value
Liabilities associated with assets held for sale
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 $0.10 par value. Authorized 800,000,000 shares;
issued 444,214,000 in 2007 and 444,040,000 in 2006
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income
Treasury stock, at cost. 11,000 shares in 2006

Total stockholders’ equity

Commitments and contingencies (Note 8)

Total liabilities and stockholders’ equity

See accompanying notes to consolidated financial statements.

December 31,

2007

2006

(In millions, except share data)

1,364
372
1,779
44
120
235
3,914

48,473
20,394
28,079
1,324
6,172
1,512
455
41,456

1,360
578
97
1,004
109
82
145
282
3,657
641
6,283
488
1,236
404
699
6,042

692
574
1,324
102
232
288
3,212

39,585
16,429
23,156
1,043
5,706
1,619
327
35,063

1,154
522
82
2,205
114
53
173
342
4,645
727
4,841
302
804
429
583
5,290

44
6,743
12,813
2,405
—
22,006

44
6,840
9,114
1,444
(1)
17,442

41,456

35,063

Consolidated Statements of Operations

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Year Ended December 31,

2007

2006
(In millions, except per share amounts)

2005

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

Total revenues

Expenses and other income, net:
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

Interest expense

Change in fair value of financial instruments
Reduction of carrying value of oil and gas properties
Other income, net

Total expenses and other income, net

Earnings from continuing operations before income tax expense
Income tax expense:
Current
Deferred

Total income tax expense
Earnings from continuing operations
Discontinued operations:
Earnings from discontinued operations before income taxes

Income tax expense

Earnings from discontinued operations

Net earnings
Preferred stock dividends
Net earnings applicable to common stockholders

Basic net earnings per share:
Earnings from continuing operations
Earnings from discontinued operations
Net earnings

Diluted net earnings per share:
Earnings from continuing operations
Earnings from discontinued operations
Net earnings

Weighted average common shares outstanding:
Basic
Diluted

See accompanying notes to consolidated financial statements.

3,493
5,163
970
1,736
11,362

1,828
340
1,227
2,655
203
74
513
430
(34)
—
(98)
7,138
4,224

500
578
1,078
3,146

696
236
460
3,606
10
3,596

7.05
1.03
8.08

6.97
1.03
8.00

445
450

2,434
4,912
749
1,672
9,767

1,425
341
1,236
2,058
173
47
397
421
178
36
(115)
6,197
3,570

528
408
936
2,634

464
252
212
2,846
10
2,836

5.94
0.48
6.42

5.87
0.47
6.34

442
448

1,794
5,761
680
1,792
10,027

1,244
335
1,342
1,767
157
42
291
533
94
42
(198)
5,649
4,378

1,033
448
1,481
2,897

173
140
33
2,930
10
2,920

6.31
0.07
6.38

6.19
0.07
6.26

458
470

Consolidated Statements of Comprehensive Income

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Net earnings
Foreign currency translation:
Change in cumulative translation adjustment

Income tax benefit (expense)
Total

Derivative financial instruments:
Unrealized change in fair value
Reclassification adjustment for realized (gains) losses

included in net earnings
Income tax expense
Total

Pension and postretirement benefit plans:
Net actuarial loss and prior service cost arising in current year
Recognition of net actuarial loss and prior service cost

in net earnings

Curtailment of pension benefits
Change in additional minimum pension liability

Income tax benefit (expense)
Total

Investment in Chevron Corporation common stock:
Unrealized holding gain
Income tax expense
Total

Other comprehensive income, net of tax
Comprehensive income

Year Ended December 31,

2007

2006
(In millions)

2005

3,606

2,846

2,930

1,389
(42)
1,347

—

(1)
—
(1)

(90)

14
16
—
23
(37)

(25)
28
3

—

(2)
—
(2)

—

—
—
30
(13)
17

181
(19)
162

(255)

685
(141)
289

—

—
—
(8)
3
(5)

—
—
—
1,309
4,915

238
(86)
152
170
3,016

60
(22)
38
484
3,414

See accompanying notes to consolidated financial statements.

Consolidated Statements of Stockholders’ Equity

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Preferred
Stock

Common Stock Paid-In
Capital
Shares Amount

Additional

Accumulated
Other

Total

Retained Comprehensive Treasury Stockholders’
Earnings
(In millions)

Income

Equity

Stock

$ 1
Balance as of December 31, 2004
—
Net earnings
—
Other comprehensive income
—
Stock option exercises
—
Restricted stock grants, net of cancellations
—
Common stock repurchased
—
Common stock retired
—
Common stock dividends
—
Preferred stock dividends
Share-based compensation
—
Excess tax benefits on share-based compensation —

1
Balance as of December 31, 2005
—
Net earnings
—
Other comprehensive income
—
Adoption of FASB Statement No. 158
—
Stock option exercises
—
Restricted stock grants, net of cancellations
—
Common stock repurchased
—
Common stock retired
—
Common stock dividends
—
Preferred stock dividends
Share-based compensation
—
Excess tax benefits on share-based compensation —

1
Balance as of December 31, 2006
—
Net earnings
—
Other comprehensive income
—
Adoption of FASB Statement No. 159
—
Adoption of FASB Interpretation No. 48
—
Adoption of FASB Statement No. 158
—
Stock option exercises
—
Restricted stock grants, net of cancellations
—
Common stock repurchased
—
Common stock retired
—
Common stock dividends
—
Preferred stock dividends
Share-based compensation
—
Excess tax benefits on share-based compensation —
$ 1
Balance as of December 31, 2007

484
—
—
5
1
(47)
—
—
—
—
—

443
—
—
—
3
2
(4)
—
—
—
—
—

444
—
—
—
—
—
3
2
(5)
—
—
—
—
—
444

$ 48
—
—
—
—
—
(4)
—
—
—
—

44
—
—
—
—
—
—
—
—
—
—
—

44
—
—
—
—
—
1
—
—
(1)
—
—
—
—
$ 44

9,002
—
—
124
—
—
(2,269)
—
—
27
44

6,928
—
—
—
73
(3)
—
(278)
—
—
84
36

6,840
—
—
—
—
—
90
—
—
(362)
—
—
131
44
6,743

3,693
2,930
—
—
—
—
—
(136)
(10)
—
—

6,477
2,846
—
—
—
—
—
—
(199)
(10)
—
—

9,114
3,606
—
364
(11)
(1)
—
—
—
—
(249)
(10)
—
—
12,813

930
—
484
—
—
—
—
—
—
—
—

1,414
—
170
(140)
—
—
—
—
—
—
—
—

1,444
—
1,309
(364)
—
16
—
—
—
—
—
—
—
—
2,405

— 13,674
2,930
—
484
—
124
—
—
—
(2,275)
(2,275)
2,273
—
(136)
—
(10)
—
27
—
44
—

(2) 14,862
2,846
—
170
—
(140)
—
73
—
—
(3)
(277)
(277)
278
—
(199)
—
(10)
—
84
—
36
—

(1) 17,442
3,606
—
1,309
—
—
—
(11)
—
15
—
91
—
—
—
(362)
(362)
363
—
(249)
—
(10)
—
131
—
—
44
— 22,006

See accompanying notes to consolidated financial statements.

Consolidated Statements of Cash Flows

DEVON ENERGY CORPORATION AND SUBSIDIARIES

Cash flows from operating activities:
Net earnings
Earnings from discontinued operations, net of tax
Adjustments to reconcile earnings from continuing operations

to net cash provided by operating activities:
Depreciation, depletion and amortization
Deferred income tax expense
Net gain on sales of non-oil and gas property and equipment
Reduction of carrying value of oil and gas properties
Other noncash charges

(Increase) decrease in assets:
Accounts receivable
Other current assets
Long-term other assets
Increase (decrease) in liabilities:
Accounts payable

Income taxes payable

Debt, including current maturities
Other current liabilities
Long-term other liabilities
Cash provided by operating activities – continuing operations
Cash provided by operating activities – discontinued operations
Net cash provided by operating activities

Cash flows from investing activities:
Proceeds from sales of property and equipment
Capital expenditures, including acquisition of business
Purchases of short-term investments
Sales of short-term investments
Cash used in investing activities – continuing operations
Cash (provided by) used in investing activities – discontinued operations
Net cash used in investing activities

Cash flows from financing activities:
Net senior credit facility borrowings, net of issuance costs
Net commercial paper (repayments) borrowings, net of issuance costs
Principal payments on debt, including current maturities
Proceeds from stock option exercises
Repurchases of common stock
Dividends paid on common and preferred stock
Excess tax benefits related to share-based compensation
Net cash (used in) provided by financing activities
Effect of exchange rate changes on cash
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year (including cash
related to assets held for sale)
Cash and cash equivalents at end of year (including cash related
to assets held for sale)

Supplementary cash flow data:

Interest paid (net of capitalized interest)
Income taxes paid (continuing and discontinued operations)

See accompanying notes to consolidated financial statements.

Year Ended December 31,

2007

2006
(In millions)

2005

3,606
(460)

2,846
(212)

2,930
(33)

2,858
578
(1)
—
177

(329)
(38)
(92)

119
(28)
—
(223)
(5)
6,162
489
6,651

2,231
408
(5)
36
269

91
(33)
(58)

(175)
(245)
—
80
141
5,374
619
5,993

76
(6,158)
(934)
1,136
(5,880)
166
(5,714)

40
(7,346)
(2,395)
2,501
(7,200)
(249)
(7,449)

1,450
(804)
(567)
91
(326)
(259)
44
(371)
51
617

—
1,808
(862)
73
(253)
(209)
36
593
13
(850)

1,924
448
(150)
42
127

(151)
(16)
35

247
70
(67)
(36)
(73)
5,297
315
5,612

2,151
(3,813)
(4,020)
4,307
(1,375)
(277)
(1,652)

—
—
(1,258)
124
(2,263)
(146)
—
(3,543)
37
454

756

1,606

1,152

1,373

756

1,606

406
588

384
960

593
1,092

$
$

Notes to Consolidated Financial Statements

DEVON ENERGY CORPORATION AND SUBSIDIARIES

1. Summary of Significant Accounting Policies

Accounting policies used by Devon Energy Corporation and subsidiaries (“Devon”) reflect industry practices and conform
to accounting principles generally accepted in the United States of America. The more significant of such policies are briefly
discussed below.

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 in the United States are concentrated in the following geographic areas:

• the Mid-Continent area of the central and southern United States, principally in north and east Texas and Oklahoma;
• 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 offshore areas of the Gulf of Mexico; and
• the onshore areas of the Gulf Coast, principally in south Texas and south Louisiana.

Devon’s Canadian operations are located primarily in the provinces of Alberta, British Columbia and Saskatchewan.
Devon’s international operations — outside of North America — are located primarily in Azerbaijan, Brazil and China. In
October 2007, Devon sold its assets and terminated its operations in Egypt. In January 2007, Devon announced its plans to
divest its assets and terminate its operations in West Africa. These divestiture activities are described more fully in Note 13.

Devon also has marketing and midstream operations that perform various activities to support the oil and gas operations

of Devon as well as unrelated third parties. Such activities include marketing natural gas, crude oil and NGLs, as well as
constructing and operating pipelines, storage and treating facilities and gas processing plants.

The accounts of Devon’s controlled 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

• estimates of proved reserves and related estimates of the present value of future net revenues;
• the carrying value of oil and gas properties;
• estimates of the fair value of reporting units and related assessment of goodwill for impairment;
• asset retirement obligations;
• income taxes;
• derivative financial instruments;
• obligations related to employee benefits; and
• legal and environmental risks and exposures.

Notes

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 that 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. All costs related to
production activities, including workover costs incurred solely to maintain or increase levels of production from an existing
completion interval, are charged to expense as incurred.

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 estimated after-tax 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. 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, including derivative contracts in place that qualify for hedge accounting treatment.
None of Devon’s outstanding derivative contracts at December 31, 2007 or December 31, 2006 qualified for hedge
accounting treatment.

Any excess of the net book value, less related deferred taxes, over the ceiling 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.

Capitalized costs are depleted by an equivalent unit-of-production method, converting gas to oil at the ratio of six

thousand cubic feet of natural gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated
asset retirement costs, plus the estimated future expenditures (based on current costs) to be incurred in developing proved
reserves, net of estimated salvage values.

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.

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.

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 ranging from three to 39 years.

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing well

sites, offshore production platforms, and midstream pipelines and processing plants when there is a legal obligation
associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an
asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an
increase to the associated property and equipment on the consolidated balance sheet. If the fair value of a recorded asset
retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated
property and equipment.

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, 2007 and 2006, Devon’s short-term
investments consisted of $372 million and $574 million, respectively, of auction rate securities classified as available for sale.
Although Devon’s auction rate securities generally have contractual maturities of more than 20 years, the underlying interest
rates on such securities are scheduled to reset every 28 days. Therefore, these auction rate securities are generally 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.

Notes

Devon owns approximately 14.2 million shares of Chevron Corporation (“Chevron”) common stock. The majority of these

shares are held in connection with debt owed by Devon that contains an exchange option. This exchange option allows the
debt holders, prior to the debt’s maturity of August 15, 2008, to exchange the debt for the shares of Chevron common stock
owned by Devon. However, Devon has the option to settle any exchanges with cash equal to the market value of Chevron
common stock at the time of the exchange. As described more fully in Note 4, Devon has paid the cash equivalent of the
Chevron common stock to settle all exchange requests through December 31, 2007.

The shares of Chevron common stock and the exchange option embedded in the debt have always been recorded on
Devon’s balance sheet at fair value. However, pursuant to accounting rules prior to January 1, 2007, only the change in fair
value of the embedded option had historically been included in Devon’s results of operations. Conversely, the change in fair
value of the Chevron common stock had not been included in Devon’s results of operations, but instead had been recorded
directly to stockholders’ equity as part of “accumulated other comprehensive income.”

Effective January 1, 2007, Devon adopted Statement of Financial Accounting Standards No. 159, The Fair Value Option for

Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115. Statement No. 159 allows a
company the option to value its financial assets and liabilities, on an instrument by instrument basis, at fair value, and
include the change in fair value of such assets and liabilities in its results of operations. Devon chose to apply the provisions
of Statement No. 159 to its shares of Chevron common stock. Accordingly, beginning with the first quarter of 2007, the
change in fair value of the Chevron common stock owned by Devon, along with the change in fair value of the related
exchange option, are both included in Devon’s results of operations.

For the year ended December 31, 2007, the change in fair value of financial instruments caption on Devon’s statement of

operations includes an unrealized gain of $281 million related to the Chevron common stock and an unrealized loss of $248
million related to the embedded option. For the years ended December 31, 2006 and 2005, prior to adopting Statement No.
159, unrealized losses of $181 million and $54 million, respectively, related to the change in fair value of the embedded
option were included in the change in fair value of financial instruments caption on Devon’s statements of operations.
As of December 31, 2006, $364 million of after-tax unrealized gains related to Devon’s investment in the Chevron

common stock was included in accumulated other comprehensive income. This is the amount of unrealized gains that, prior
to Devon’s adoption of Statement No. 159, had not been recorded in Devon’s historical results of operations. Upon the
adoption of Statement No. 159 as of January 1, 2007, this $364 million of unrealized gains was reclassified on Devon’s
balance sheet from accumulated other comprehensive income to retained earnings.

In conjunction with the adoption of Statement No. 159, Devon also adopted on January 1, 2007 Statement of Financial

Accounting Standards No. 157, Fair Value Measurements. Statement No. 157 provides a common definition of fair value,
establishes a framework for measuring fair value and expands disclosures about fair value measurements, but does not
require any new fair value measurements. The adoption of Statement No. 157 had no impact on Devon’s financial
statements, but the adoption did result in additional required disclosures as set forth in Note 5.

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 2007, 2006 and 2005. 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, 2007 and 2006.

The increase in goodwill from 2006 to 2007 is largely due to changes in the exchange rate between the U.S. dollar and the
Canadian dollar.

United States
Canada

International
Total

December 31,

2007

2006

(In millions)

3,050
3,054
68
6,172

3,053
2,585
68
5,706

Notes

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,

delivery has occurred, title has transferred and 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. Taxes assessed by
governmental authorities on oil, gas and NGL revenues are presented separately from such revenues as production taxes in
the statement of operations.

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. 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. 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.

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, delivery or performance has occurred, title has transferred and collectibility of the revenue is
probable. Revenues and expenses attributable to Devon’s gas and NGL purchase and processing contracts are reported on a
gross basis when 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

During 2007, 2006 and 2005, no purchaser accounted for more than 10% of Devon’s revenues from continuing

operations.

Derivative Financial Instruments

The majority of Devon’s derivative financial instruments consist of commodity financial instruments used to manage
Devon’s cash flow 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 cash flow effects of interest rate fluctuations
on interest expense for variable-rate debt instruments, or the fair value effects of interest rate fluctuations on fixed-rate
debt. Devon also has an embedded option derivative related to the fair value of its debentures exchangeable into shares of
Chevron common stock.

All derivative financial instruments are recognized at their current fair value in the fair value of financial instruments

caption on the balance sheet. Changes in the fair value of these derivative financial instruments are recorded in the
statement of operations unless specific hedge accounting criteria are met. If such criteria are met for cash flow hedges, the
effective portion of the change in the fair value is recorded directly to accumulated other comprehensive income, a
component of stockholders’ equity, until the hedged transaction occurs. The ineffective portion of the change in fair value is
recorded in the statement of operations. If such criteria are met for fair value hedges, the change in the fair value is recorded
in the statement of operations with an offsetting amount recorded for the change in fair value of the hedged item.

A derivative financial instrument qualifies for hedge accounting treatment if Devon designates the instrument as such on

the date the derivative contract is entered into or the date of a business combination or other transaction that includes
derivative contracts. Additionally, Devon must document the relationship between the hedging instrument and hedged item,
as well as the risk-management objective and strategy for undertaking the instrument. Devon must also assess, both at the
instrument’s inception and on an ongoing basis, whether the derivative is highly effective in offsetting the change in cash
flow of the hedged item.

During 2007 and 2006, Devon entered into and acquired certain commodity derivative instruments. For such

instruments, Devon chose not to meet the necessary criteria to qualify these derivative instruments for hedge accounting
treatment. Therefore, for the years ended December 31, 2007 and 2006, the changes in fair value related to these
instruments were recorded to gas sales in the statements of operations. Such amounts recorded were a $25 million loss and
a $37 million gain in 2007 and 2006, respectively.

The following table presents the components of the 2007, 2006 and 2005 change in fair value of financial instruments
presented in the accompanying statement of operations. Significant items are discussed in more detail following the table.

Notes

Losses (gains) from:

Option embedded in exchangeable debentures
Chevron common stock
Interest rate swaps

Non-qualifying commodity hedges

Ineffectiveness of commodity hedges
Total change in fair value of financial instruments

2007

2006
(In millions)

2005

248
(281)
(1)
—
—
(34)

181
—
(3)
—
—
178

54
—
(4)
39
5
94

The change in the fair value of the embedded option relates to the debentures exchangeable into shares of Chevron
common stock (see Note 4). These unrealized losses were caused primarily by increases in the price of Chevron’s common
stock.

As previously discussed in the Short-Term Investments and Other Marketable Securities section of Note 1, beginning in

2007, the change in fair value of the Chevron common stock owned by Devon is included in Devon’s results of operations
rather than accumulated other comprehensive income. The unrealized gain on this investment resulted from the increase in
the price of Chevron’s common stock.

In addition to the changes in fair value of Devon’s interest rate swaps presented in the table above, settlements on these

interest rate swaps increased interest expense by $4 million, $14 million and $10 million in 2007, 2006 and 2005,
respectively.

During 2005, Devon had a number of commodity derivative instruments that qualified for hedge accounting treatment as

described above. During 2005, certain of these derivatives ceased to qualify for hedge accounting treatment. In the third
quarter of 2005, certain oil derivatives ceased to qualify for hedge accounting primarily as a result of deferred production
caused by hurricanes in the Gulf of Mexico. Because these contracts no longer qualified for hedge accounting, Devon
recognized $39 million in losses as change in fair value of derivative financial instruments in the accompanying 2005
statement of operations.

In addition to the changes in fair value of non-qualifying commodity hedges presented in the table above, Devon also
recognized in 2005 a $55 million loss related to certain oil hedges that no longer qualified for hedge accounting due to the
effect of the 2005 property divestiture program. These commodity instruments related to 5,000 barrels per day of U.S. oil
production and 3,000 barrels per day of Canadian oil production from properties that were sold as part of Devon’s divestiture
program. This loss is presented in other income in the 2005 statement of operations.

The following table presents the balances of Devon’s accumulated net gain (loss) on cash flow hedges included in

accumulated other comprehensive income (in millions).

December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007

$
$
$
$

(286)
3
1
—

By using derivative financial 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 financial instrument that results from a change in commodity prices,

interest rates or other relevant underlyings. 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 financial instruments for speculative trading purposes.

Notes

Stock Options

Effective January 1, 2006, Devon adopted Statement of Financial Accounting Standard No. 123(R), Share-Based Payment,

(“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires equity-classified, 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. Under the modified prospective transition method, share-based awards
granted or modified on or after January 1, 2006, are recognized in compensation expense over the applicable vesting period.
Also, any previously granted awards that were not fully vested as of January 1, 2006 are recognized as compensation
expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon Devon’s
adoption of SFAS No. 123(R).

Prior to adopting SFAS No. 123(R), Devon accounted for its fixed-plan employee stock options using the intrinsic-value
based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, (“APB No.
25”) and related interpretations. This method required compensation expense to be recorded on the date of grant only if the
current market price of the underlying stock exceeded the exercise price.

Had the fair value provisions of SFAS No. 123(R) been applied in 2005, Devon’s 2005 net earnings and net earnings per
share would have differed from the amounts actually reported as shown in the following table (in millions, except per share
amounts).

Net earnings available to common stockholders, as reported
Add share-based employee compensation expense included in reported

net earnings, net of related tax expense

Deduct total share-based employee compensation expense determined

under fair value based method for all awards (see Note 9), 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

2,920

(44)
2,894

6.38
6.26

6.32
6.21

$
$

Prior to the adoption of SFAS No. 123(R), Devon presented all tax benefits of deductions resulting from the exercise of
stock options as operating cash inflows in the statement of cash flows. SFAS No. 123(R) requires the cash inflows resulting
from tax deductions in excess of the compensation expense recognized for those stock options (“excess tax benefits”) to be
classified as financing cash inflows. As required by SFAS No. 123(R), Devon recognized $44 million and $36 million of excess
tax benefits as financing cash inflows for 2007 and 2006, respectively. In 2005, excess tax benefits of $44 million were
classified as operating cash inflows.

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the United States and
by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions using the
asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their
respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected
utilization of existing tax net operating loss carryforwards 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.

At December 31, 2007, undistributed earnings of foreign subsidiaries included in continuing operations were determined

to be permanently reinvested. Therefore, no U.S. deferred income taxes were provided on such amounts at December 31,
2007. If it becomes apparent that some or all of the undistributed earnings will be distributed, Devon would then record
taxes on those earnings.

In June 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109. Interpretation No. 48 prescribes a threshold for
recognizing the financial statement effects of a tax position when it is more likely than not, based on the technical merits,
that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and

Notes

subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate
settlement with a taxing authority. Liabilities for unrecognized tax benefits related to such tax positions are included in other
long-term liabilities unless the tax position is expected to be settled within the upcoming year, in which case the liabilities
are included in accrued expenses and other current liabilities. Interest and penalties related to unrecognized tax benefits are
included in income tax expense.

On January 1, 2007, Devon adopted Interpretation No. 48 and recorded an $11 million reduction to the January 1, 2007
balance of retained earnings related to unrecognized tax benefits. The $11 million included $8 million for related interest and
penalties. An additional $3 million of liabilities were recorded with a corresponding increase to goodwill.

As a result of the adoption of Interpretation No. 48, certain liabilities included in income taxes payable and deferred
income taxes were reclassified to other current and long-term liabilities in the accompanying balance sheet. The total $14
million increase in liabilities included a $17 million increase to long-term liabilities, partially offset by a $3 million reduction
to current liabilities.

Additional information regarding Devon’s unrecognized tax benefits, including changes in such amounts during 2007, is

provided in Note 12.

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, as calculated using the treasury stock
method, reflects the potential dilution that could occur if Devon’s dilutive outstanding stock options were exercised. For
2005, the calculation of diluted shares also assumed that Devon’s previously outstanding zero coupon convertible senior
debentures were converted to common stock.

The following table reconciles earnings from continuing operations and common shares outstanding used in the

calculations of basic and diluted earnings per share for 2007, 2006 and 2005.

Net
Earnings
Applicable to
Common
Stockholders

weighted
Average
Common
Shares
Outstanding
(In millions, except per share amounts)

Net
Earnings
per Share

Year Ended December 31, 2007:

Earnings from continuing operations
Less preferred stock dividends
Basic earnings per share
Dilutive effect of potential common shares issuable

upon the exercise of outstanding stock options

Diluted earnings per share
Year Ended December 31, 2006:

Earnings from continuing operations
Less preferred stock dividends
Basic earnings per share
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options

Diluted earnings per share
Year Ended December 31, 2005:

Earnings from continuing operations
Less preferred stock dividends
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 (increase in
net earnings is net of income tax expense of $14 million) (1)

Diluted earnings per share

(1) The senior convertible debentures were retired in June 2005 prior to their stated maturity.

$ 3,146
(10)
3,136

—
$ 3,136

$ 2,634
(10)
2,624

—
$ 2,624

$ 2,897
(10)
2,887

—

24
$ 2,911

445

5
450

442

6
448

458

4
470

$ 7.05

$ 6.97

$ 5.94

$ 5.87

$ 6.31

$ 6.19

Notes

Certain options to purchase shares of Devon’s common stock were excluded from the dilution calculations because the

options were antidilutive. These excluded options totaled 2 million, 3 million and 0.2 million in 2007, 2006 and 2005,
respectively.

Foreign Currency Translation Adjustments

The U.S. dollar is the functional currency for Devon’s consolidated operations except its Canadian subsidiaries, which use

the Canadian dollar as the 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. Canadian 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. The following table presents the
balances of Devon’s cumulative translation adjustments included in accumulated other comprehensive income (in millions).

December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007

$
$
$
$

1,054
1,216
1,219
2,566

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. Liabilities for environmental
remediation or restoration claims are recorded when it is probable that obligations have been incurred and the amounts can
be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with
Devon’s accounting policy for property and equipment. Reference is made to Note 8 for a discussion of amounts recorded
for these liabilities.

Recently Issued Accounting Standards Not Yet Adopted

In December 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting

In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160, Noncontrolling Interests in

Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. A noncontrolling interest,
sometimes called a minority interest, is the portion of equity in a subsidiary not attributable, directly or indirectly, to a
parent. Statement No. 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a subsidiary must be reported
as a component of consolidated equity separate from the parent’s equity. Additionally, the amounts of consolidated net
income attributable to both the parent and the noncontrolling interest must be reported separately on the face of the
income statement. Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier
adoption is prohibited. Devon does not expect the adoption of Statement No. 160 to have a material impact on its financial
statements and related disclosures.

2. Accounts Receivable

The components of accounts receivable include the following:

Oil, gas and NGL revenue
Joint interest billings

Marketing and midstream revenue
Other

Gross accounts receivable
Allowance for doubtful accounts

Net accounts receivable

3. Property and Equipment and Asset Retirement Obligations

Property and equipment include 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

Notes

2006

951
209
138
31
1,329
(5)
1,324

December 31,

(In millions)

2007

1,184
240
183
177
1,784
(5)
1,779

December 31,

2007

2006

(In millions)

42,141
3,417
(19,507)
26,051
2,915
(887)
2,028

28,079

33,922
3,293
(15,756)
21,459
2,370
(673)
1,697

23,156

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 quarterly. Subject to industry conditions, evaluation of most of these properties, and therefore the
inclusion of their costs in the amortized capital costs, is expected to be completed within five years.

The following is a summary of Devon’s oil and gas properties not subject to amortization as of December 31, 2007:

Acquisition costs
Exploration costs
Development costs
Capitalized interest

Total oil and gas properties not subject to amortization

Chief Acquisition

Costs Incurred In

2007

2006

2005
(In millions)

223
424
94
68
809

1,226
378
114
49
1,767

253
123
22
30
428

Prior to
2005

316
92
—
5
413

Total

2,018
1,017
230
152
3,417

On June 29, 2006, Devon acquired the oil and gas assets of privately-owned Chief Holdings LLC (“Chief”). Devon paid
$2.0 billion in cash and assumed approximately $0.2 billion of net liabilities in the transaction for a total purchase price of
$2.2 billion. Devon funded the acquisition price, and the immediate retirement of $180 million of assumed debt, with $718
million of cash on hand and approximately $1.4 billion of borrowings issued under its commercial paper program. The
acquired oil and gas properties consisted of 99.7 MMBoe (unaudited) of proved reserves and leasehold totaling 169,000 net
acres located in the Barnett Shale area of north Texas. Devon allocated approximately $1.0 billion of the purchase price to
proved reserves and approximately $1.2 billion to unproved properties.

Notes

Property Divestitures

In November 2006 and January 2007, Devon announced plans to divest its operations in Egypt and West Africa. In
October 2007, Devon completed the sale of its Egyptian operations and received proceeds of $341 million. See Note 13 for
more discussion regarding these divestitures.

Asset Retirement Obligations

Following is a reconciliation of the asset retirement obligation for the years ended December 31, 2007 and 2006.

Asset retirement obligation as of beginning of year

Liabilities incurred
Liabilities settled
Liabilities assumed by others
Revision of estimated obligation
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,

2007

2006

(In millions)

857
57
(68)
(3)
311
74
90
1,318
82
1,236

636
102
(59)
—
135
47
(4)
857
53
804

During 2007 and 2006, Devon recognized a $311 million and $135 million revision to its asset retirement obligation,

respectively. The primary factors causing the 2007 fair value increase were an overall increase in abandonment cost
estimates and an increase in the assumed inflation rate. The effect of these factors was partially offset by the effect of an
increase in the discount rate used to calculate the present value of the obligations. The primary factor causing the 2006 fair
value increase was an overall increase in abandonment cost estimates.

4. Debt and Related Expenses

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

2007

December 31,

(In millions)

1,450
1,004

381
271
(11)

—
177
1,750
350
125
150
1,250
1,000
—
31
7,928
1,004
6,924

2006

—
1,808

444
316
(33)

400
177
1,750
350
125
150
1,250
1,000
(5)
41
7,773
2,205
5,568

Senior Credit Facility borrowings
Commercial paper
Debentures exchangeable into shares of Chevron common stock:

4.90% due August 15, 2008
4.95% due August 15, 2008
Discount on exchangeable debentures

Other debentures and notes:

4.375% due October 1, 2007
10.125% due November 15, 2009
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
Fair value adjustment on debt related to interest rate swaps
Net premium on other debentures and notes

Less amount classified as short-term debt
Long-term debt

Maturities of short-term and long-term debt as of December 31, 2007, excluding premiums and discounts, are as follows

Notes

(in millions):

2008
2009
2010
2011
2012
2013 and thereafter

Total

Credit Lines

1,004
177
—
2,100
2,102
2,525
7,908

Devon has two revolving lines of credit that can be accessed to provide liquidity. As of December 31, 2007, Devon’s
combined available capacity under these credit facilities, net of $198 million of outstanding letters of credit and $1.0 billion
of outstanding commercial paper, was $1.3 billion.

Devon’s $2.5 billion five-year, syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) matures on April
7, 2012, and all amounts outstanding will be due and payable at that time unless the maturity is extended. Prior to each April
7 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.

The Senior Credit Facility includes a five-year revolving Canadian subfacility in a maximum amount of U.S. $500 million.
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. However, Devon may elect to borrow at
the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $1.8 million that is payable quarterly
in arrears. As of December 31, 2007, there were $1.4 billion of borrowings under the Senior Credit Facility at an average rate
of 5.27%.

On August 7, 2007, Devon established a new $1.5 billion 364-day, syndicated, unsecured revolving senior credit facility

(the “Short-Term Facility”). This facility provides Devon with provisional interim liquidity until the proceeds from divestitures
of assets in Africa are received. The Short-Term Facility was also used to support an increase in Devon’s commercial paper
program from $2 billion to $3.5 billion.

The Short-Term Facility matures on August 5, 2008. At that time, all amounts outstanding will be due and payable unless

the maturity is extended. Prior to August 5, 2008, Devon has the option to convert any outstanding principal amount of
loans under the Short-Term Facility to a term loan that will be repayable in a single payment on August 4, 2009.

Amounts borrowed under the Short-Term Facility 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 Short-Term
Facility currently provides for an annual facility fee of approximately $0.8 million that is payable quarterly in arrears. As of
December 31, 2007, there were no borrowings under the Short-Term Facility.

The Senior Credit Facility and Short-Term Facility contain only one material financial covenant. This covenant requires
Devon’s ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of
total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated
financial statements. As defined in the agreement, total funded debt excludes the debentures that are exchangeable into
shares of Chevron common stock. Also, total capitalization is adjusted to add back noncash financial writedowns such as full
cost ceiling impairments or goodwill impairments. As of December 31, 2007, Devon was in compliance with this covenant.
Devon’s debt-to-capitalization ratio at December 31, 2007, as calculated pursuant to the terms of the agreement, was 23.8%.

Commercial Paper

Devon also has access to short-term credit under its commercial paper program. Total borrowings under the commercial

paper program may not exceed $3.5 billion. Also, any borrowings under the commercial paper program reduce available
capacity under the Senior Credit Facility or the Short-Term Facility on a dollar-for-dollar basis. Commercial paper debt
generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears 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,
LIBOR, or the money market rate as found on the commercial paper market. As of December 31, 2007, Devon had $1.0
billion of commercial paper debt outstanding at an average rate of 5.07%. The average borrowing rate for Devon’s $1.8 billion
of commercial paper debt outstanding at December 31, 2006 was 5.37%. Outstanding commercial paper is classified as
short-term debt in the accompanying consolidated balance sheets.

Notes

Exchangeable Debentures

The exchangeable debentures consist of $381 million of 4.90% debentures and $271 million of 4.95% debentures. The
exchangeable debentures were issued on August 3, 1998 and mature August 15, 2008. The exchangeable debentures are
callable at 100.5% of principal as of December 31, 2007.

The exchangeable debentures are exchangeable at the option of the holders at any time prior to maturity, unless

previously redeemed, for shares of Chevron common stock that Devon owns. In lieu of delivering Chevron 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 Chevron 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.

During 2007, certain holders of exchangeable debentures exercised their option to exchange their debentures for shares

of Chevron common stock prior to the debentures’ August 15, 2008 maturity date. Devon elected to pay the exchanging
debenture holders cash totaling $167 million in lieu of delivering shares of Chevron common stock. As a result of these
exchanges, Devon retired outstanding exchangeable debentures with a book value totaling $105 million and reduced the
related embedded derivative option’s balance by $62 million.

As of December 31, 2007, Devon owned approximately 14.2 million shares of Chevron common stock. The majority of

these shares are held for possible exchange when holders redeem their exchangeable debentures. Each $1,000 principal
amount of the exchangeable debentures is exchangeable into 18.6566 shares of Chevron common stock, an exchange rate
equivalent to $53.60 per share of Chevron stock.

As of December 31, 2007, the exchangeable debentures are due within one year. However, Devon continues to classify

this debt as long-term because it has the intent and ability to refinance these debentures on a long-term basis with the
available capacity under its existing credit facilities or other long-tem financing arrangements.

The exchangeable debentures were assumed as part of the 1999 acquisition of PennzEnergy. As a result, 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 was allocated between the interest-bearing debt and
the option to exchange Chevron 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%.

Other Debentures and Notes

Following are descriptions of the various other debentures and notes outstanding at December 31, 2007, as listed in the

table presented at the beginning of this note.

Ocean Debt

As a result of the merger with Ocean Energy, Inc., which closed April 25, 2003, Devon assumed $1.8 billion of debt. The

table below summarizes the debt assumed that 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 resulting from fair values exceeding face values are being amortized using the effective
interest method. All of the notes are general unsecured obligations of Devon.

Debt Assumed

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)

10.125% Debentures due November 15, 2009

Fair Value of
Debt Assumed
(In millions)

$
$
$

406
147
169

Effective Rate of
Debt Assumed

4.9%
5.5%
6.5%

These debentures were assumed as part of the PennzEnergy acquisition. The fair value of the debentures was determined

using August 17, 1999, market interest rates. As a result, a premium was recorded on these debentures, which lowered the
effective interest rate to 8.9%. The premium is being amortized using the effective interest method.

Notes

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”), a wholly-owned finance

subsidiary, 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 acquisition of Anderson Exploration.

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 used to retire other indebtedness.

Interest Expense

The following schedule includes the components of interest expense between 2005 and 2007.

2007

Year Ended December 31,
2006
(In millions)

2005

Interest based on debt outstanding

Capitalized interest
Other interest

Total interest expense

508
(102)
24
430

486
(79)
14
421

507
(70)
96
533

During 2005, Devon redeemed its $400 million 6.75% notes due March 15, 2011 and its zero coupon convertible senior

debentures prior to their scheduled maturity dates. The other interest category in the table above includes $81 million in
2005 related to these early retirements.

5. Fair Value Measurements

Certain of Devon’s assets and liabilities are reported at fair value in the accompanying balance sheets. Such assets and

liabilities include amounts for both financial and nonfinancial instruments. The following tables provide fair value
measurement information for such assets and liabilities as of December 31, 2007 and 2006.

The carrying values of cash and cash equivalents, accounts receivable and accounts payable (including income taxes

payable and accrued expenses) included in the accompanying consolidated balance sheets approximated fair value at
December 31, 2007 and 2006. These assets and liabilities are not presented in the following tables.

As of December 31, 2007

Fair Value Measurements using:

Quoted
Prices in
Active
Markets
(Level 1)
(In millions)

372
1,324
—
—
(1,140)
—

Significant
Other
Observable
Inputs
(Level 2)

Significant
unobservable
Inputs
(Level 3)

—
—
12
(488)
(7,915)
—

—
—
—
—
—
(1,318)

Carrying
Amount

Total Fair
Value

$
$
$
$
$
$

372
1,324
12
(488)
(7,928)
(1,318)

372
1,324
12
(488)
(9,055)
(1,318)

Financial Assets (Liabilities):
Short-term investments

Investment in Chevron common stock

Oil and gas price swaps and collars
Embedded option in exchangeable debentures
Debt

Asset retirement obligation

Notes

Financial Assets (Liabilities):
Short-term investments

Investment in Chevron common stock

Oil and gas price swaps and collars

Interest rate swaps

Embedded option in exchangeable debentures
Debt

Asset retirement obligation

As of December 31, 2006

Fair Value Measurements using:

Quoted
Prices in
Active
Markets
(Level 1)
(In millions)

574
1,043
—
—
—
(1,056)
—

Significant
Other
Observable
Inputs
(Level 2)

Significant
unobservable
Inputs
(Level 3)

—
—
39
(6)
(302)
(7,669)
—

—
—
—
—
—
—
(857)

Carrying
Amount

Total Fair
Value

$
$
$
$
$
$
$

574
1,043
39
(6)
(302)
(7,773)
(857)

574
1,043
39
(6)
(302)
(8,725)
(857)

Statement No. 157 (see Note 1) establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used

to measure fair value. As presented in the table above, this hierarchy consists of three broad levels. Level 1 inputs on the
hierarchy consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest
priority. Level 3 inputs have the lowest priority. Devon uses appropriate valuation techniques based on the available inputs
to measure the fair values of its assets and liabilities. When available, Devon measures fair value using Level 1 inputs because
they generally provide the most reliable evidence of fair value. Devon only uses Level 3 inputs to measure the fair value of its
asset retirement obligation.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table

above.

Level 1 Fair Value Measurements

Short-term Investments — The fair values of these investments are based on quoted market prices. Devon’s short-term

investments as of December 31, 2007 and 2006 consisted entirely of auction rate securities. All such securities held at
December 31, 2007 were collateralized by student loans which are substantially guaranteed by the United States
government. Subsequent to December 31, 2007, Devon has reduced its auction rate securities holdings to $153 million.
However, beginning on February 8, 2008, Devon experienced difficulty selling certain of the securities due to the failure of
the auction mechanism which provides liquidity to these securities. An auction failure means that the parties wishing to sell
securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned
every 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Accordingly, there may be
no effective mechanism for selling these securities, and the securities Devon owns may become long-term investments. At
this time, Devon does not believe its auction rate securities are impaired or that the failure of the auction mechanism will
have a material impact on its liquidity.

Investment in Chevron Corporation common stock — The fair value of this investment is based on a quoted market price.
Debt — Certain of the fixed-rate debt instruments actively trade in an established market. The fair values of this debt are

based on quotes obtained from brokers.

Level 2 Fair Value Measurements

Oil and gas price swaps and collars — The fair values of the oil and gas price swaps and collars are estimated using internal
discounted cash flow calculations based upon forward commodity price curves, quotes obtained from brokers for contracts
with similar terms or quotes obtained from counterparties to the agreements.

Embedded option in exchangeable debentures — The embedded option is not actively traded in an established market.
Therefore, its fair value is estimated using quotes obtained from a broker for trades near the fair value measurement date.
Debt — Certain of the fixed-rate debt instruments do not actively trade in an established market. The fair values of this

debt are estimated by discounting the principal and interest payments at rates available for debt with similar terms and
maturity. The fair values of floating-rate debt are estimated to approximate the carrying amounts because the interest rates
paid on such debt are generally set for periods of three months or less.

Interest rate swaps — The fair values of the interest rate swaps are estimated using internal discounted cash flow
calculations based upon forward interest-rate yield curves or quotes obtained from counterparties to the agreements.

Notes

Level 3 Fair Value Measurements

Asset retirement obligation — The fair values of the asset retirement obligations are estimated using internal discounted
cash flow calculations based upon Devon’s estimates of future retirement costs. A reconciliation of the beginning and ending
balances of Devon’s asset retirement obligation, including a revision of the estimated fair value in 2007 and 2006, is
presented in Note 3.

6. 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 employees’ years of service
and compensation and are funded from assets held in the plans’ trusts.

Devon’s funding policy regarding the Qualified Plans is to contribute the amount of funds necessary so that the Qualified

Plans’ assets will be approximately equal to the related accumulated benefit obligation. As of December 31, 2007 and 2006,
the fair values of the Qualified Plans’ assets were $619 million and $590 million, respectively, which were $62 million and $59
million more, respectively, 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 employees’ years of service and
compensation. For certain Supplemental Plans, Devon has established trusts to fund these plans’ benefit obligations. The
total value of these trusts was $59 million at both December 31, 2007 and 2006, and is 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”) that provide benefits for substantially all
U.S. 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 Devon’s future cost-sharing intentions. Devon’s funding policy for the Postretirement Plans is to fund the benefits
as they become payable with available cash and cash equivalents.

Revisions to Retirement Plans

In the second quarter of 2007, Devon adopted an enhanced defined contribution structure related to its 401(k) Incentive
Savings Plan (“401(k) Plan”) to be effective January 1, 2008. Participants in this enhanced defined contribution structure will
continue to receive a discretionary match of a percentage of their contributions to the 401(k) Plan. These participants will
also receive additional, nondiscretionary contributions by Devon calculated as a percentage of annual compensation. The
percentage will vary based on the employees’ years of service.

On or before November 15, 2007, existing eligible employees elected to either continue to participate in the defined
benefit plan or participate in the enhanced defined contribution structure of the 401(k) Plan. Employees who elected to
continue participating in the defined benefit plans will continue to accrue benefits under the existing provisions of such
plans. Employees who elected to participate in the enhanced defined contribution structure will receive enhanced
contributions to the 401(k) Plan and will retain the benefits that they have accrued under the defined benefit plan as of
December 31, 2007. However, such employees will only be entitled to the benefits that have accrued in the defined benefit
plans as of December 31, 2007, after all applicable vesting requirements have been met. Employees hired on or after
October 1, 2007 will not have an election and will only participate in the 401(k) Plan and the enhanced defined contribution
structure.

For those employees who elected to participate in the enhanced defined contribution structure, Devon’s pension benefit
obligation included $16 million related to projected future years of service for these employees. Because this portion of the
employees’ benefits was curtailed upon their election, Devon reduced its pension liabilities by $16 million in the fourth
quarter of 2007.

Change in Measurement Date

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, Employers’ Accounting for

Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R).

Notes

Statement No. 158 requires the measurement of plan assets and benefit obligations as of the date of the employer’s fiscal
year-end, beginning with fiscal years ending after December 15, 2008. Although not required until 2008, Devon adopted this
measurement-date requirement in the second quarter of 2007 and changed its measurement date from November 30 to
December 31. As a result, Devon used data as of December 31, 2006 to remeasure its plans assets and benefit obligations
previously measured using data as of November 30, 2006. As a result of the remeasurement, Devon recognized the following
amounts in the second quarter of 2007.

Other long-term liabilities
Deferred income tax liabilities
Retained earnings
Accumulated other comprehensive income
General and administrative expenses

Benefit Obligations and Plan Assets

Increase (Decrease)
(In millions)

$
$
$
$
$

(27)
9
(1)
16
(3)

The following table presents the status of Devon’s pension and other postretirement benefit plans for 2007 and 2006. 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, 2007 and 2006 was $693 million and $652 million, respectively.

Pension Benefits

2007

2006

Other
Postretirement Benefits

$
$
$
$
$
$

33
34
36
39
43
296

6
6
6
6
6
30

Expected 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 2008, $8 million of pension benefits is expected to be
funded from the trusts established for the Supplemental Plans and all $6 million of other postretirement benefits 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’s 401(k) Plan 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 $18 million, $15 million and $12 million for the years ended December 31, 2007,
2006 and 2005, respectively.

As previously discussed in “Revisions to Retirement Plans” above, in 2007 Devon adopted an enhanced defined

contribution structure related to its 401(k) Plan to be effective January 1, 2008. Participants who elected to participate in this
enhanced defined contribution structure, as well as all employees hired on or after October 1, 2007, will continue to receive
a discretionary match of a percentage of their contributions to the 401(k) Plan. These participants will also receive
additional, nondiscretionary contributions by Devon calculated as a percentage of annual compensation. The percentage will
vary based on the employees’ years of service.

Devon has defined contribution pension plans for its Canadian employees. Devon makes a contribution to each employee

that 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 2007,
2006 and 2005, Devon’s combined contributions to the Canadian defined contribution plan and the Canadian savings plan
were $14 million, $12 million and $10 million, respectively.

7. 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.

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.

Notes

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, 2007, 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.

Stock Repurchases

In June 2007, Devon’s Board of Directors approved an ongoing, annual stock repurchase program to minimize dilution

resulting from restricted stock issued to, and options exercised by, employees. This repurchase program authorized the
repurchase of up to 4.5 million shares in 2007. In 2008, the ongoing annual stock repurchase program authorizes the
repurchase of up to 4.8 million shares or $422 million, whichever amount is reached first. In anticipation of the completion of
the West African divestitures (see Note 13), Devon’s Board of Directors has approved a separate program to repurchase up
to 50 million shares. This program expires on December 31, 2009.

These programs are in addition to a 50 million share repurchase program approved by Devon’s Board of Directors in
August 2005, which expired on December 31, 2007. Additionally, in October 2004 Devon’s Board of Directors approved a 50
million share repurchase program that was completed in August 2005.

During the three-year period ended December 31, 2007, Devon repurchased 55.2 million shares at a total cost of $2.8
billion, or $51.49 per share, under these repurchase programs. During 2007, Devon repurchased 4.1 million shares at a cost
of $326 million, or $79.80 per share. During 2006, Devon repurchased 4.2 million shares at a cost of $253 million, or $59.61
per share. During 2005, Devon repurchased 46.9 million shares at a cost of $2.3 billion, or $48.28 per share.

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 that 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 $0.01 per

right until the rights become exercisable.

Dividends

Devon paid common stock dividends of $249 million (or $0.56 per share), $199 million (or $0.45 per share) and $136

million (or $0.30 per share) in 2007, 2006 and 2005 respectively. Devon paid $10 million in 2007, 2006 and 2005 to preferred
stockholders.

8. 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.

Notes

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, 2007, Devon’s balance sheet included $3 million
of noncurrent accrued liabilities, reflected in other liabilities, related to these and other environmental remediation liabilities.
Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the
current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon
subsidiaries are PRPs, Devon’s conclusion is based in large part on (i) Devon’s participation in consent decrees with both
other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for
remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and
(iii) the availability of other defenses to liability. As a result, Devon’s monetary exposure is not expected to be material.

Royalty Matters

Numerous gas producers and related parties, including Devon, have been named in various lawsuits alleging violation of

the federal False Claims Act. The suits allege that the producers and related parties used below-market prices, improper
deductions, improper measurement techniques and transactions with affiliates, which resulted in underpayment of royalties
in connection with natural gas and NGLs 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 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. On April 12, 2007, the court entered a trial plan and scheduling order in which the case will proceed in phases.
Two phases have been scheduled to date, with the first scheduled to begin in August 2008 and the second scheduled to
begin in February 2009. Devon is not included in the groups of defendants selected for these first two phases. 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.

In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to
encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain
federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have contained
price thresholds, such that if the market prices for oil or natural gas exceeded the thresholds for a given year, royalty relief
would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price thresholds. The MMS in
2006 informed Devon and other oil and gas companies that the omission of price thresholds from these leases was an error
on its part and was not its intention. Accordingly, the MMS invited Devon and the other affected oil and gas producers to
renegotiate the terms and conditions of the 1998 and 1999 leases to add price threshold provisions to the lease agreements
for periods after October 1, 2006. Devon has not entered into any renegotiated leases.

The U.S. House of Representatives in January 2007 passed legislation that would have required companies to renegotiate
the 1998 and 1999 leases as a condition of securing future federal leases. This legislation was not passed by the U.S. Senate.
However, Congress may consider similar legislation in the future. Although Devon has not signed renegotiated leases, it has
accrued in its 2007 financial statements approximately $28 million for royalties that would be due if price thresholds were
added to its 1998 and 1999 leases effective October 1, 2006.

Additionally, Devon has $22 million accrued at the end of 2007 for royalties related to leases issued under the Deep

Water Royalty Relief Act in years other than 1998 or 1999. The leases issued in these other years did include price
thresholds, but in October 2007 a federal district court ruled in favor of a plaintiff who had challenged the legality of
including price thresholds in these leases. This judgment is subject to appeal, and Devon will continue to accrue for royalties
on these leases until the matter is resolved.

Notes

Hurricane Contingencies

Historically, Devon maintained a comprehensive insurance program that included coverage for physical damage to its

offshore facilities caused by hurricanes. Devon’s historical insurance program also included substantial business
interruption coverage, which Devon is utilizing to recover costs associated with the suspended production related to
hurricanes that struck the Gulf of Mexico in the third quarter of 2005. Under the terms of this insurance program, Devon was
entitled to be reimbursed for the portion of production suspended longer than forty-five days, subject to upper limits to oil
and natural gas prices. Also, the terms of the insurance include a standard, per-event deductible of $1 million for offshore
losses as well as a $15 million aggregate annual deductible.

Based on current estimates of physical damage and the anticipated length of time Devon will have had production
suspended, Devon expects its policy recoveries will exceed repair costs and deductible amounts. This expectation is based
upon several variables, including the $467 million received in 2006 as a full settlement of the amount due from Devon’s
primary insurers and $13 million received in 2007 as a full settlement of the amount due from certain of Devon’s secondary
insurers. As of December 31, 2007, $330 million of these proceeds had been utilized as reimbursement of past repair costs
and deductible amounts. The remaining proceeds of $150 million will be utilized as reimbursement of Devon’s anticipated
future repair costs. Devon continues to negotiate with its other secondary insurers and expects to receive additional policy
recoveries as a result of such negotiations.

Should Devon’s total policy recoveries, including the partial settlements already received from Devon’s primary and
secondary insurers, exceed all repair costs and deductible amounts, such excess will be recognized as other income in the
statement of operations in the period in which such determination can be made.

The policy underlying the insurance program terms described above expired on August 31, 2006. Devon’s current

insurance program includes business interruption and physical damage coverage for its business. However, due to significant
changes in the insurance marketplace, Devon has only been able to obtain a de minimis amount of coverage for any damage
that may be caused by named windstorms in the Gulf of Mexico. Devon has not experienced any losses under this new
insurance arrangement through December 31, 2007.

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.

Commitments

Devon has certain drilling and facility obligations under contractual agreements with third party service providers to
procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Included
in the $3.9 billion total of “Drilling and Facility Obligations” in the table below is $2.4 billion that relates to long-term
contracts for three deepwater drilling rigs and certain other contracts for onshore drilling and facility obligations in which
drilling or facilities construction has not commenced. The $2.4 billion represents the gross commitment under these
contracts. Devon’s ultimate payment for these commitments will be reduced by the amounts billed to its partners when net
working interests are ultimately determined. Payments for these commitments, net of amounts billed to partners, will be
capitalized as a component of oil and gas properties.

Devon has certain firm transportation agreements that represent “ship or pay” arrangements whereby Devon has

committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. Devon has entered into these
agreements to aid the movement of its production to market. Devon expects to have sufficient production to utilize the
majority of these transportation services.

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 $43 million, $36 million and $35
million in 2007, 2006 and 2005, 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 Boomvang field was divested as part of the 2005
property divestiture program. The Nansen operating lease is for a 20-year term and contains various options whereby Devon
may purchase the lessors’ interests in the spar. Total rental expense included in lease operating expenses under both the
Nansen and Boomvang operating leases was $12 million, $12 million and $14 million in 2007, 2006 and 2005, respectively.
Devon has guaranteed that the Nansen spar will have a residual value at the end of the operating lease equal to at least 10%
of the fair value of the spar at the inception of the lease. The total guaranteed value is $14 million in 2022. However, such
amount may be reduced under the terms of the lease agreement. As a result of the sale of the Boomvang field, Devon is

Notes

subleasing the Boomvang Spar. If the sublessee were to default on its obligation, Devon would continue to be obligated to
pay the periodic lease payments and any guaranteed value required at the end of the term.

Devon has a floating, production, storage and offloading facility (“FPSO”) that is being used in the Panyu project offshore

China and is being leased under operating lease arrangements. This lease expires in September 2009. Devon also has an
FPSO that is being used in the Polvo project offshore Brazil. This lease expires in 2014. Total rental expense included in lease
operating expenses under the China and Brazil operating leases was $17 million, $9 million and $7 million in 2007, 2006 and
2005, respectively.

The following is a schedule by year of future minimum payments for drilling and facility obligations, firm transportation

agreements and leases that have initial or remaining noncancelable lease terms in excess of one year as of December 31,
2007. The schedule includes $144 million of drilling and facility obligations related to Devon’s discontinued operations (see
Note 13).

Year Ending December 31,

2008
2009
2010
2011
2012
Thereafter

Total payments

9. Share-Based Compensation

Drilling
and Facility
Obligations

Firm
Transportation
Agreements

Office and
Equipment
Leases
(In millions)

Spar
Leases

FPSO
Leases

983
713
541
406
341
951
3,935

170
180
149
128
106
307
1,040

62
51
41
36
21
20
231

11
11
11
11
11
130
185

31
29
23
23
23
33
162

On June 8, 2005, Devon’s stockholders adopted the 2005 Long-Term Incentive Plan, which expires on June 8, 2013.
Devon’s stockholders adopted certain amendments to this plan on June 7, 2006. This plan, as amended, authorizes the
Compensation Committee, which consists of non-management members of Devon’s Board of Directors, to grant
nonqualified and incentive stock options, restricted stock awards, Canadian restricted stock units, performance units,
performance bonuses, stock appreciation rights and cash-out rights to eligible employees. The plan also authorizes the grant
of nonqualified stock options, restricted stock awards and stock appreciation rights to directors. A total of 32 million shares
of Devon common stock have been reserved for issuance pursuant to the plan. To calculate shares issued under the plan,
options granted represent one share and other awards represent 2.2 shares.

Devon also has stock option plans that were adopted in 2003 and 1997 under which stock options and restricted stock
awards were issued to key management and professional employees. Options granted under these plans remain exercisable
by the employees owning such options, but no new options or restricted stock awards will be granted under these plans.
Devon also has stock options outstanding that were assumed as part of the acquisitions of Ocean, Mitchell Energy &
Development Corp., Santa Fe Snyder and PennzEnergy.

As discussed in Note 1, on January 1, 2006, Devon changed its method of accounting for share-based compensation from
the APB No. 25 intrinsic value accounting method to the fair value recognition provisions of SFAS No. 123(R). The following
table presents the effects of share-based compensation included in Devon’s accompanying statement of operations for the
years ended December 31, 2007, 2006 and 2005.

Gross general and administrative expense
Share-based compensation expense capitalized pursuant to the
full cost method of accounting for oil and gas properties

Related income tax benefit

Stock Options

2007

2006
(In millions)

2005

$
$

146

44
34

26
23

—
11

Under Devon’s 2005 Long-Term Incentive Plan, the exercise price of stock options granted may not be less than the
estimated fair market value of the stock at the date of grant. In addition, options granted are exercisable during a period
established for each grant, which may not exceed eight years from the date of grant. The recipient must pay the exercise
price in cash or in common stock, or a combination thereof, at the time that the option is exercised. Options granted
generally have a vesting period that ranges from three to four years.

Notes

The fair value of stock options on the date of grant is expensed over the applicable vesting period. Devon estimates the

fair values of stock options granted using a Black-Scholes option valuation model, which requires Devon to make several
assumptions. The volatility of Devon’s common stock is based on the historical volatility of the market price of Devon’s
common stock over a period of time equal to the expected term of the option and ending on the grant date. The dividend
yield is based on Devon’s historical and current yield in effect at the date of grant. The risk-free interest rate is based on the
zero-coupon U.S. Treasury yield for the expected term of the option at the date of grant. The expected term of the options is
based on historical exercise and termination experience for various groups of employees and directors. Each group is
determined based on the similarity of their historical exercise and termination behavior.

The following table presents a summary of the grant-date fair values of stock options granted and the related

assumptions for the years ended December 31, 2007, 2006 and 2005. All such amounts represent the weighted-average
amounts for each year.

Grant-date fair value
Volatility factor
Dividend yield
Risk-free interest rate
Expected term (in years)

2007

2006

2005

26.43
31.6%
0.7%
5.0%
4.0

22.41
32.2%
0.5%
5.7%
4.0

19.65
31.0%
0.6%
4.4%
4.2

The following table presents a summary of Devon’s outstanding stock options as of December 31, 2007, including

changes during the year then ended.

Outstanding at December 31, 2006

Granted
Exercised
Forfeited

Outstanding at December 31, 2007
Vested and expected to vest at December 31, 2007
Exercisable at December 31, 2007

weighted
Average
Exercise
Price

weighted
Average
Remaining
Contractual
Price
(In years)

Aggregate
Intrinsic
Value
(In millions)

$
$
$
$
$
$
$

38.24
87.68
29.43
53.97
46.66
46.39
35.58

3.8
3.8
3.2

$
$
$

584
582
536

Options
(In thousands)

15,383
1,913
(3,123)
(367)
13,806
13,688
10,059

The aggregate intrinsic value of stock options that were exercised during 2007, 2006 and 2005 was $151 million, $119

million and $149 million, respectively. As of December 31, 2007, Devon’s unrecognized compensation cost related to
unvested stock options was $93 million. Such cost is expected to be recognized over a weighted-average period of 2.4 years.

Restricted Stock Awards and Units

Under Devon’s 2005 Long-Term Incentive Plan, restricted stock awards and units are subject to the terms, conditions,

restrictions and/or limitations, if any, that the Compensation Committee deems appropriate, including restrictions on
continued employment. Generally, restricted stock awards and units vest over a minimum restriction period of at least three
years from the date of grant. During the vesting period, recipients of restricted stock awards receive dividends that are not
subject to restrictions or other limitations. The fair value of restricted stock awards and units on the date of grant is
expensed over the applicable vesting period. Devon estimates the fair values of restricted stock awards and units as the
closing price of Devon’s common stock on the grant date of the award or unit.

The following table presents a summary of Devon’s unvested restricted stock awards as of December 31, 2007, including

changes during the year then ended.

Notes

Unvested at December 31, 2006

Granted
Vested
Forfeited

Unvested at December 31, 2007

Restricted
Stock
Awards

weighted
Average
grant-Date
Fair Value
(In thousands)

5,162
2,026
(1,574)
(188)
5,426

$
$
$
$
$

58.35
87.81
51.66
57.33
71.38

The aggregate fair value of restricted stock awards that vested during 2007, 2006 and 2005 was $136 million, $82 million

and $51 million, respectively. As of December 31, 2007, Devon’s unrecognized compensation cost related to unvested
restricted stock awards and units was $341 million. Such cost is expected to be recognized over a weighted-average period of
2.8 years.

10. Reduction of Carrying Value of Oil and gas Properties

During 2006 and 2005, Devon reduced the carrying value of certain of its oil and gas properties due to full cost ceiling

limitations and unsuccessful exploratory activities. A summary of these reductions and additional discussion is provided
below.

Brazil - unsuccessful exploratory reduction
Russia - ceiling test reduction
Total

2006 Reductions

Year Ended December 31,

2006

2005

gross

Net of Taxes

gross

Net of Taxes

(In millions)

16
20
36

16
10
26

42
—
42

During the second quarter of 2006, Devon drilled two unsuccessful exploratory wells in Brazil and determined that the
capitalized costs related to these two wells should be impaired. Therefore, in the second quarter of 2006, Devon recognized
a $16 million impairment of its investment in Brazil equal to the costs to drill the two dry holes and a proportionate share of
block-related costs. There was no tax benefit related to this impairment. The two wells were unrelated to Devon’s Polvo
development project in Brazil.

As a result of a decline in projected future net cash flows, the carrying value of Devon’s Russian properties exceeded the
full cost ceiling by $10 million at the end of the third quarter of 2006. Therefore, Devon recognized a $20 million reduction of
the carrying value of its oil and gas properties in Russia, offset by a $10 million deferred income tax benefit.

2005 Reduction

Prior to the fourth quarter of 2005, Devon was capitalizing the costs of previous unsuccessful efforts in Brazil pending
the determination of whether proved reserves would be recorded in Brazil. At the end of 2005, it was expected that a small
initial portion of the proved reserves ultimately expected at Polvo would be recorded in 2006. Based on preliminary
estimates developed in the fourth quarter of 2005, the value of this initial partial booking of proved reserves was not
sufficient to offset the sum of the related proportionate Polvo costs plus the costs of the previous unrelated unsuccessful
efforts. Therefore, Devon determined that the prior unsuccessful costs unrelated to the Polvo project should be impaired.
These costs totaled approximately $42 million. There was no tax benefit related to this Brazilian impairment.

Notes

11. Other Income

The components of other income include the following:

2007

Year Ended December 31,
2006
(In millions)

2005

Interest and dividend income

Net gain on sales of non-oil and gas property and equipment
Loss on derivative financial instruments
Other

Total

89
1
—
8
98

100
5
—
10
115

95
150
(48)
1
198

12. Income Taxes

Income Tax Expense

The earnings from continuing operations before income taxes and the components of income tax expense (benefit) for

the years 2007, 2006 and 2005 were as follows:

2007

Year Ended December 31,
2006
(In millions)

2005

Earnings from continuing operations before income taxes:

U.S.
Canada

International

Total

Current income tax expense:

U.S. federal
Various states
Canada and various provinces

International

Total current tax expense

Deferred income tax expense (benefit):

U.S. federal
Various states
Canada and various provinces

International

Total deferred tax expense

Total income tax expense

2,642
685
897
4,224

83
16
136
265
500

745
28
(166)
(29)
578
1,078

2,435
751
384
3,570

292
7
143
86
528

456
77
(105)
(20)
408
936

3,254
899
225
4,378

811
26
106
90
1,033

271
(18)
217
(22)
448
1,481

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

related to international operations.

Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to earnings

from continuing operations before income taxes as a result of the following:

2007

Year Ended December 31,
2006
(In millions)

2005

Expected income tax expense based on U.S. statutory tax rate of 35%
Effect of Canadian tax rate reductions
State income taxes
Repatriation of earnings
Taxation on foreign operations
Other

Total income tax expense

1,478
(261)
30
—
(165)
(4)
1,078

1,249
(243)
55
—
(120)
(5)
936

1,532
(14)
6
28
(50)
(21)
1,481

Notes

In 2007, 2006 and 2005, deferred income taxes were reduced $261 million, $243 million and $14 million, respectively, due

to successive Canadian statutory rate reductions that were enacted in each such year.

In 2006, deferred income taxes increased $39 million due to the effect of a new income-based tax enacted by the state of
Texas that replaced a previous franchise tax. The new tax was effective January 1, 2007. The $39 million increase is included
in 2006 state income taxes in the above table.

In 2005, Devon recognized $28 million of taxes related to its repatriation of $545 million to the United States. The cash
was repatriated to take advantage of U.S. tax legislation, which allowed qualifying companies to repatriate cash from foreign
operations at a reduced income tax rate. Substantially all of the cash repatriated by Devon in 2005 related to prior earnings
of its Canadian subsidiary.

Deferred Tax Assets and Liabilities

At December 31, 2007, 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. For financial purposes, the tax effects of these carryforwards, net of any valuation allowances, have been
recognized as reductions to the net deferred tax liability at December 31, 2007.

Jurisdiction

Various U.S. states
Canada
Brazil

Years of Expiration

Carryforward Amounts
(In millions)

2008 – 2026
2010 – 2027
Indefinite

$
$
$

494
15
188

The tax effects of temporary differences that gave rise to significant portions of the deferred tax assets and liabilities at

December 31, 2007 and 2006 are presented below:

Deferred tax assets:

Net operating loss carryforwards
Fair value of financial instruments
Asset retirement obligations
Pension benefit obligations

Insurance proceeds

Other

Total deferred tax assets

Valuation allowance

Net 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

Chevron Corporation common stock
Long-term debt
Other
Total deferred tax liabilities
Net deferred tax liability

December 31,

2007

2006

(In millions)

92
167
387
93
21
102
862
(50)
812

(6,152)
(431)
(216)
(11)
(6,810)
(5,998)

57
97
265
81
113
103
716
(22)
694

(5,374)
(326)
(148)
(34)
(5,882)
(5,188)

As shown in the above table, Devon has recognized $812 million of deferred tax assets as of December 31, 2007, net of a
$50 million valuation allowance. Included in total deferred tax assets is $92 million related to various carryforwards available
to offset future income taxes. The carryforwards include state net operating loss carryforwards, which expire primarily
between 2008 and 2026, Canadian net operating loss carryforwards, which expire primarily between 2010 and 2027, and
Brazilian net operating loss 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.

Notes

Devon expects the tax benefits from the state and Canadian net operating loss carryforwards to be utilized between

2008 and 2012. 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 state and Canadian tax carryforwards prior to their expiration.

Included in deferred tax assets for net operating loss carryforwards as of December 31, 2007 and 2006 is $64 million and

$36 million, respectively, related to the Brazil carryforward. Although this carryforward has no expiration, management is
uncertain whether Devon’s future taxable income will be sufficient to utilize a substantial portion of its Brazil carryforward.
This uncertainty is based upon annual limitations on the amount of net operating loss carryforwards available to reduce
taxable income, Devon’s lack of historical taxable income in Brazil and the exploratory nature of several of Devon’s current
projects in Brazil. Therefore, as of December 31, 2007 and 2006, Devon had a valuation allowance of $50 million and $22
million, respectively, related to this carryforward.

Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits for the year ended December 31, 2007 (in

millions).

Balance as of January 1, 2007

Increases due to:
Tax positions taken in current year
Tax positions taken in prior years
Accrual of interest related to tax positions taken

Decreases due to:

Tax positions taken in prior years
Lapse of statute of limitations
Settlements

Foreign currency translation adjustment
Balance as of December 31, 2007

122

4
10
3

(5)
(20)
(9)
6
111

Devon’s unrecognized tax benefit balance at January 1, 2007 included $114 million of unrecognized tax benefits before

interest and penalties, and $8 million of interest and penalties. Included in Devon’s unrecognized tax benefits of $111 million
as of December 31, 2007 was $74 million that, if recognized, would affect Devon’s effective income tax rate.

Included below is a summary of the tax years, by jurisdiction, that remain subject to examination by taxing authorities.

Jurisdiction

U.S. federal
Various U.S. states
Canada federal
Various Canadian provinces
Various other foreign jurisdictions

Tax Years Open

2002-2007
2001-2007
2001-2007
2001-2007
2003-2007

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is currently

in the final stages of the administrative review process for certain open tax years. In addition, Devon is currently subject to
various income tax audits that have not reached the administrative review process. As a result, Devon cannot reasonably
anticipate the extent that the liabilities for unrecognized tax benefits will increase or decrease within the next twelve
months.

Notes

13. Discontinued Operations

Egypt and West Africa

In November 2006 and January 2007, Devon announced its plans to divest its operations in Egypt and West Africa,

including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region. Pursuant to accounting rules for
discontinued operations, Devon has classified all 2007 and prior period amounts related to its operations in Egypt and West
Africa as discontinued operations.

In October 2007, Devon completed the sale of its Egyptian operations and received proceeds of $341 million. As a result

of this sale, Devon recognized a $90 million after-tax gain in the fourth quarter of 2007. In November 2007, Devon
announced an agreement to sell its operations in Gabon for $205.5 million. Devon is finalizing purchase and sales
agreements and obtaining the necessary partner and government approvals for the remaining properties in the West African
divestiture package. Devon is optimistic it can complete these sales during the first half of 2008.

Revenues related to Devon’s operations in Egypt and West Africa totaled $781 million, $929 million and $714 million
during 2007, 2006 and 2005, respectively. The following table presents the main classes of assets and liabilities associated
with Devon’s operations in Egypt and West Africa as of December 31, 2007 and 2006.

Assets:
Cash
Accounts receivable
Other current assets
Current assets

Long-term assets – property and equipment, net of

accumulated depreciation, depletion and amortization

Liabilities:

Accounts payable – trade
Revenues and royalties due to others

Income taxes payable

Current portion of asset retirement obligation
Accrued expenses and other current liabilities

Current liabilities

Asset retirement obligation, long-term
Deferred income taxes
Other liabilities

Long-term liabilities

December 31,

(In millions)

2007

9
83
28
120

2006

64
101
67
232

1,512

1,619

23
11
100
9
2
145

35
366
3
404

41
7
115
8
2
173

38
375
16
429

Reductions of carrying value related to discontinued operations

Based on drilling activities in Nigeria, Devon reduced the carrying value of its Nigerian assets held for sale in 2007. As a

result, earnings from discontinued operations in 2007 include a $13 million after-tax loss ($64 million pre-tax).

As a result of unsuccessful exploratory activities in Egypt during 2006, the net book value of Devon’s Egyptian oil and gas

properties, less related deferred income taxes, exceeded the ceiling by $18 million as of the end of September 30, 2006.
Therefore, in 2006, Devon recognized an $18 million after-tax loss ($31 million pre-tax).

Due to unsuccessful drilling activities in Nigeria, in the first quarter of 2006, Devon recognized an $85 million impairment

of its investment in Nigeria equal to the costs to drill two dry holes and a proportionate share of block-related costs. There
was no income tax benefit related to this impairment.

Notes

14. Segment Information

Devon manages its business by country. As such, Devon identifies its segments based on geographic areas. Devon has
three reportable segments: its operations in the U.S., its operations in Canada, and its international operations outside of
North America. Substantially all of these segments’ operations involve oil and gas producing activities. Certain information
regarding such activities for each segment is included in Note 15.

Following is certain financial information regarding Devon’s segments for 2007, 2006 and 2005. The revenues reported

are all from external customers.

As of December 31, 2007:
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

Year Ended December 31, 2007:
Revenues:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues

Interest expense

Change in fair value of financial instruments
Other income, net

Total expenses and other income, net

Earnings from continuing operations before income tax expense (benefit)

Income tax expense (benefit):
Current
Deferred

Total income tax expense (benefit)

Earnings from continuing operations
Discontinued operations:

Earnings from discontinued operations before income taxes

Income tax expense

Earnings from discontinued operations

Net earnings
Preferred stock dividends
Net earnings applicable to common stockholders

Capital expenditures, continuing operations

u.S.

Canada

International

Total

(In millions)

1,601

852

1,461

3,914

18,019
3,049
1,651
24,320

2,661
3,948
594
1,137
3,980
12,000
24,320

8,909
3,055
49
12,865

561
2,976
569
45
2,011
6,703
12,865

1,151
68
1,591
4,271

435
—
73
409
51
3,303
4,271

28,079
6,172
3,291
41,456

3,657
6,924
1,236
1,591
6,042
22,006
41,456

u.S.

Canada

International

Total

(In millions)

1,313
3,742
773
1,693
7,521

1,005
212
1,211
1,672
180
38
399
228
(32)
(34)
4,879
2,642

100
773
873
1,769

—
—
—
1,769
10
1,759

4,522

804
1,410
197
43
2,454

654
4
16
740
21
32
119
202
(2)
(17)
1,769
685

135
(166)
(31)
716

—
—
—
716
—
716

1,376
11
—
—
1,387

169
124
—
243
2
4
(5)
—
—
(47)
490
897

265
(29)
236
661

696
236
460
1,121
—
1,121

1,350

455

3,493
5,163
970
1,736
11,362

1,828
340
1,227
2,655
203
74
513
430
(34)
(98)
7,138
4,224

500
578
1,078
3,146

696
236
460
3,606
10
3,596

6,327

As of December 31, 2006:
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

Year Ended December 31, 2006:
Revenues:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues

Interest expense

Change in fair value of financial instruments
Reduction of carrying value of oil and gas properties
Other income, net

Total expenses and other income, net

Earnings from continuing operations before income tax expense

Income tax expense (benefit):
Current
Deferred

Total income tax expense
Earnings from continuing operations
Discontinued operations:

Earnings from discontinued operations before income taxes

Income tax expense

Earnings from discontinued operations

Net earnings
Preferred stock dividends
Net earnings applicable to common stockholders

Capital expenditures, continuing operations

Notes

u.S.

Canada

International

Total

(In millions)

1,307

616

1,289

3,212

15,253
3,053
1,289
20,902

3,693
2,594
387
864
3,351
10,013
20,902

6,929
2,585
35
10,165

569
2,974
360
16
1,831
4,415
10,165

974
68
1,665
3,996

383
—
57
434
108
3,014
3,996

23,156
5,706
2,989
35,063

4,645
5,568
804
1,314
5,290
17,442
35,063

u.S.

Canada

International

Total

(In millions)

1,218
3,445
548
1,641
6,852

813
235
1,226
1,311
154
25
316
199
181
—
(43)
4,417
2,435

299
533
832
1,603

—
—
—
1,603
10
1,593

603
1,456
201
31
2,291

543
7
10
644
18
21
92
222
(3)
—
(14)
1,540
751

143
(105)
38
713

—
—
—
713
—
713

613
11
—
—
624

69
99
—
103
1
1
(11)
—
—
36
(58)
240
384

86
(20)
66
318

464
252
212
530
—
530

5,814

1,670

405

2,434
4,912
749
1,672
9,767

1,425
341
1,236
2,058
173
47
397
421
178
36
(115)
6,197
3,570

528
408
936
2,634

464
252
212
2,846
10
2,836

7,889

Notes

Year Ended December 31, 2005:
Revenues:
Oil sales
Gas sales
NGL sales
Marketing and midstream revenues

Total revenues

Interest expense

Change in fair value of financial instruments
Reduction of carrying value of oil and gas properties
Other income, net

Total expenses and other income, net

Earnings from continuing operations before income tax expense

Income tax expense (benefit):
Current
Deferred

Total income tax expense
Earnings from continuing operations
Discontinued operations:

Earnings from discontinued operations before income taxes

Income tax expense

Earnings from discontinued operations

Net earnings
Preferred stock dividends
Net earnings applicable to common stockholders

Capital expenditures, continuing operations

u.S.

Canada

International

Total

(In millions)

1,062
3,929
484
1,780
7,255

710
273
1,336
1,137
141
25
245
224
86
—
(176)
4,001
3,254

837
253
1,090
2,164

—
—
—
2,164
10
2,154

2,200

353
1,814
196
12
2,375

498
6
6
570
14
16
59
309
8
—
(10)
1,476
899

106
217
323
576

—
—
—
576
—
576

1,707

379
18
—
—
397

36
56
—
60
2
1
(13)
—
—
42
(12)
172
225

90
(22)
68
157

173
140
33
190
—
190

1,794
5,761
680
1,792
10,027

1,244
335
1,342
1,767
157
42
291
533
94
42
(198)
5,649
4,378

1,033
448
1,481
2,897

173
140
33
2,930
10
2,920

3,995

15. 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. This supplemental information excludes amounts for all periods presented related to Devon’s
discontinued operations in Egypt and West Africa.

Costs Incurred

The following tables reflect the costs incurred in oil and gas property acquisition, exploration and development activities:

Total
Year Ended December 31,
2006
(In millions)

2007

2005

Property acquisition costs:

Proved properties
Unproved properties

Exploration costs
Development costs
Costs incurred

100

10
206
891
4,994
6,101

1,113
1,481
881
4,035
7,510

54
346
826
2,629
3,855

Property acquisition costs:

Proved properties
Unproved properties

Exploration costs
Development costs
Costs incurred

Property acquisition costs:

Proved properties
Unproved properties

Exploration costs
Development costs
Costs incurred

Property acquisition costs:

Proved properties
Unproved properties

Exploration costs
Development costs
Costs incurred

Notes

Domestic
Year Ended December 31,
2006
(In millions)

2007

2005

3
156
569
3,542
4,270

1,066
1,366
547
2,558
5,537

5
106
422
1,597
2,130

Canada
Year Ended December 31,
2006
(In millions)

2007

2005

7
49
211
1,098
1,365

23
70
217
1,244
1,554

49
239
361
1,020
1,669

International
Year Ended December 31,
2006
(In millions)

2007

2005

—
1
111
354
466

24
45
117
233
419

—
1
43
12
56

Pursuant to the full cost method of accounting, Devon capitalizes certain of its general and administrative expenses that
are related to property acquisition, exploration and development activities. Such capitalized expenses, which are included in
the costs shown in the preceding tables, were $312 million, $243 million and $158 million in the years 2007, 2006 and 2005,
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 $65 million, $49 million and $40 million in the years 2007, 2006 and 2005, respectively.

Results of Operations for Oil and Gas Producing Activities

The following tables include revenues and expenses associated directly with Devon’s continuing 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.

2007

Total
Year Ended December 31,
2006
(In millions, except per
equivalent barrel amounts)

2005

Oil, gas and NGL sales
Production and operating expenses
Depreciation, depletion and amortization
Accretion of asset retirement obligation
General and administrative expenses
Reduction of carrying value of oil and gas properties

Income tax expense
Results of operations
Depreciation, depletion and amortization per Boe

$
$

9,626
(2,168)
(2,655)
(74)
(226)
—
(1,253)
3,250
11.85

8,095
(1,766)
(2,058)
(47)
(155)
(36)
(1,191)
2,842
10.27

8,235
(1,579)
(1,767)
(42)
(105)
(42)
(1,631)
3,069
8.56

101

Notes

Oil, gas and NGL sales
Production and operating expenses
Depreciation, depletion and amortization
Accretion of asset retirement obligation
General and administrative expenses

Income tax expense
Results of operations
Depreciation, depletion and amortization per Boe

Oil, gas and NGL sales
Production and operating expenses
Depreciation, depletion and amortization
Accretion of asset retirement obligation
General and administrative expenses

Income tax expense
Results of operations
Depreciation, depletion and amortization per Boe

$
$

2007

Domestic
Year Ended December 31,
2006
(In millions, except per
equivalent barrel amounts)

2005

5,828
(1,217)
(1,672)
(38)
(167)
(962)
1,772
11.44

5,211
(1,048)
(1,311)
(25)
(115)
(996)
1,716
9.89

5,475
(983)
(1,137)
(25)
(84)
(1,145)
2,101
8.35

2007

Canada
Year Ended December 31,
2006
(In millions, except per
equivalent barrel amounts)

2005

2,411
(658)
(740)
(32)
(36)
(63)
882
12.73

2,260
(550)
(644)
(21)
(29)
(144)
872
11.17

2,363
(504)
(570)
(16)
(20)
(426)
827
9.20

2007

International
Year Ended December 31,
2006
(In millions, except per
equivalent barrel amounts)

2005

1,387
(293)
(243)
(4)
(23)
—
(228)
596
12.31

624
(168)
(103)
(1)
(11)
(36)
(51)
254
10.02

397
(92)
(60)
(1)
(1)
(42)
(60)
141
7.20

In 2007, 2006 and 2005, the Canadian income tax amounts in the tables above were reduced by $261 million, $243 million

and $14 million, respectively, due to statutory rate reductions that were enacted in each such year.

Quantities of Oil and Gas Reserves

Set forth below is a summary of the reserves that were evaluated, either by preparation or audit, by independent

petroleum consultants for each of the years ended 2007, 2006 and 2005.

2007

2006

2005

Prepared

Audited

Prepared

Audited

Prepared

Audited

6%
34%
99%
19%

83%
51%
—
69%

7%
46%
99%
28%

81%
39%
—
61%

9%
46%
98%
31%

79%
26%
—
54%

Domestic
Canada

International

Total

102

Notes

“Prepared” reserves are those quantities of reserves that were prepared by an independent petroleum consultant.

“Audited” reserves are those quantities of revenues that 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.

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, 2007. Additional discussion of the significant proved reserve changes
follows the tables below.

Proved reserves as of December 31, 2004

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2005

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2006

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2007
Proved developed reserves as of:

December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007

Oil
(MMBbls)

gas
(Bcf)

Total

Natural
gas
Liquids
(MMBbls)

Total
(MMBoe)

484
(12)
19
166
2
(46)
(58)
555
(22)
4
139
—
(42)
—
634
11
31
56
1
(55)

(1)

677

332
306
318
391

7,385
79
(7)

1,220
10
(819)
(676)
7,192
(87)

(107)
1,490
584
(808)
(5)
8,259
169
155

1,272
15
(863)
(13)
8,994

6,177
6,073
6,484
7,255

232
4
16
30
—
(24)
(12)
246
(7)
5
45
9
(23)
—
275
5
20
47
—
(26)
—
321

204
216
229
274

1,946
5
35
399
4
(206)
(183)
2,000
(44)
(8)
433
106
(200)
(1)

2,286
44
75
315

3
(224)
(3)

2,496

1,566
1,535
1,628
1,874

103

Notes

Proved reserves as of December 31, 2004

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2005

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2006

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2007
Proved developed reserves as of:

December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007

Proved reserves as of December 31, 2004

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2005

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2006

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2007
Proved developed reserves as of:

December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007

104

Domestic

Oil
(MMBbls)

gas
(Bcf)

Natural
gas
Liquids
(MMBbls)

Total
(MMBoe)

203
6
2
16
—
(25)
(29)
173

—
—
16
—
(19)
—
170
4
6
9
1
(19)
(1)
170

168
149
147
148

4,936
58

238
793
—
(555)
(306)
5,164
(110)

(11)

1,298
580
(566)
—
6,355
119
174

1,133
10
(635)
(13)

7,143

182
3
19
20
—
(18)
(9)
197
(3)
6
43
9
(19)
—

233
5
21
45
—
(22)
—

282

4,105
4,343
4,916
5,743

161
175
196
244

Canada

1,208
19
61
169
—
(136)
(89)
1,232

(22)
5
274
105
(132)
—
1,462
29
56
242
2
(146)
(3)
1,642

1,014
1,049
1,163
1,349

Oil
(MMBbls)

147
—
2

144

(13)
(29)
253
(19)

(1)

109
—
(13)
—
329
16
13
46
—
(16)
—
388

123
103
112
195

gas
(Bcf)

2,420

(242)
427

10
(261)
(370)
2,006

23
(84)
193

4
(241)
(5)
1,896

50
(19)
139

5
(227)
—
1,844

2,043
1,708
1,560
1,506

Natural
gas
Liquids
(MMBbls)

Total
(MMBoe)

50
1
(3)
10
—
(6)
(3)
49
(4)
(1)
2
—
(4)
—
42
—
(1)
2
—
(4)
—
39

43
41
33
30

600
4
(41)
225
4
(62)
(94)
636
(20)
(16)
145
1
(58)
(1)
687
25
7
72
1
(58)
—
734

507
429
405
476

Proved reserves as of December 31, 2004

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2005

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2006

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves

Proved reserves as of December 31, 2007
Proved developed reserves as of:

December 31, 2004
December 31, 2005
December 31, 2006
December 31, 2007

Notes

International (1)

Oil
(MMBbls)

gas
(Bcf)

Natural
gas
Liquids
(MMBbls)

Total
(MMBoe)

134
(18)
15
6
—
(8)
—
129

(3)
5
14
—
(10)
—
135

(9)
12
1
—
(20)
—
119

41
54
59
48

29
(1)
(3)
—
—
(3)
—
22
—
(12)
(1)
—
(1)
—
8
—
—
—
—
(1)
—
7

29
22
8
6

—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—

—
—
—
—

138
(18)
15
5
—
(8)
—
132
(2)
3
14
—
(10)
—
137
(10)
12
1
—
(20)
—
120

45
57
60
49

(1)

Included in the International quantities of proved reserves as of December 31, 2007, 2006, 2005 and 2004 are 86 MMBoe, 103 MMBoe, 105 MMBoe and 115 MMBoe, respectively, which are attributable
to production sharing contracts with various foreign governments.

Noteworthy amounts included in the categories of proved reserve changes for the years 2007, 2006 and 2005 in the

above tables include:

Extensions and Discoveries: 2007 – Of the 315 MMBoe of 2007 extensions and discoveries, 119 MMBoe related to the
Barnett Shale area in Texas, 34 MMBoe related to the Carthage area in east Texas, 22 MMBoe related to the Jackfish steam-
assisted gravity drainage project in Canada, 20 MMBoe related to the Lloydminster heavy oil development in Canada, 17
MMBoe related to the Washakie area in southern Wyoming and 15 MMBoe related to the Woodford Shale in eastern
Oklahoma.

The 2007 extensions and discoveries included 154 MMBoe related to additions from Devon’s infill drilling activities,

including 96 MMBoe related to the Barnett Shale and 19 MMBoe related to Lloydminster.

2006 – Of the 433 MMBoe of 2006 extensions and discoveries, 143 MMBoe related to the Barnett Shale, 88 MMBoe

related to Jackfish, 30 MMBoe related to Carthage and 20 MMBoe related to Washakie.

The 2006 extensions and discoveries included 202 MMBoe related to additions from Devon’s infill drilling activities,

including 127 MMBoe related to the Barnett Shale area and 20 MMBoe related to the Lloydminster area in Canada.

2005 – Of the 399 MMBoe of 2005 extensions and discoveries, 118 MMBoe related to Jackfish, 54 MMBoe related to the

Barnett Shale, and 40 MMBoe related to the Deep Basin in Canada.

The 2005 extensions and discoveries included 76 MMBoe related to additions from Devon’s infill drilling activities,
including 19 MMBoe related to the Barnett Shale, 16 MMBoe related to Carthage and eight MMBoe related to the Permian
Basin in New Mexico and west Texas.

Purchase of Reserves: The 2006 total included 100 MMBoe located in the Barnett Shale that was acquired in the June 2006

Chief acquisition.

Sale of Reserves: The 2005 total included 176 MMBoe of reserves related to non-core oil and gas properties in the offshore

Gulf of Mexico an onshore in the United States and Canada.

Revisions Other Than Price: The 2007 total included performance revisions of 39 MMBoe in the Barnett Shale, 13 MMBoe

at Jackfish, 13 MMBoe in Carthage and 7 MMBoe in China.

105

Notes

Standardized Measure of Discounted Future Net Cash Flows

The tables below reflect the standardized measure of discounted future net continuing cash flows relating to Devon’s

interest in proved reserves:

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Future cash inflows
Future costs:

Development
Production

Future income tax expense
Future net cash flows
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

2007

Total
December 31,
2006
(In millions)

2005

$ 111,156

77,951

89,144

(9,974)
(39,047)
(17,752)
44,383
(20,912)
$ 23,471

(8,116)
(28,537)
(12,241)
29,057
(13,428)
15,629

(5,488)
(24,296)
(19,773)
39,587
(17,958)
21,629

2007

Domestic
December 31,
2006
(In millions)

2005

$ 72,109

47,980

55,954

(5,673)
(25,112)
(12,526)
28,798
(14,119)
$ 14,679

(4,919)
(18,858)
(7,588)
16,615
(7,938)
8,677

(2,954)
(16,213)
(12,582)
24,205
(11,258)
12,947

2007

Canada
December 31,
2006
(In millions)

2005

$ 28,684

22,575

26,277

(3,380)
(10,331)
(3,729)
11,244
(5,282)
5,962

(2,395)
(7,431)
(3,614)
9,135
(4,318)
4,817

(1,984)
(6,344)
(5,986)
11,963
(5,332)
6,631

2007

International
December 31,
2006
(In millions)

2005

$ 10,363

7,396

6,913

(921)
(3,604)
(1,497)
4,341
(1,511)
2,830

(802)
(2,248)
(1,039)
3,307
(1,172)
2,135

(550)
(1,739)
(1,205)
3,419
(1,368)
2,051

Future cash inflows are computed by applying year-end prices (averaging $60.42 per barrel of oil, $6.01 per Mcf of gas
and $50.57 per barrel of natural gas liquids at December 31, 2007) 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.

106

Notes

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 $10.0 billion of future development costs as of the end of 2007, $1.9 billion, $1.6 billion and $1.3
billion are estimated to be spent in 2008, 2009 and 2010, respectively.

Future development costs include not only development costs, but also future dismantlement, abandonment and

rehabilitation costs. Included as part of the $10.0 billion of future development costs are $2.1 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.

Changes Relating to the Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net continuing cash flows attributable to Devon’s

proved reserves are as follows:

2007

Year Ended December 31,
2006
(In millions)

2005

Beginning balance
Oil, gas and NGL sales, net of production costs
Net changes in prices and production costs
Extensions and discoveries, net of future development costs
Purchase of reserves, net of future development costs
Development costs incurred during the period that

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 and foreign exchange rates
Ending balance

$ 15,629
(7,233)
9,582
4,131
51

1,887
566
(50)
2,214
(2,863)
(443)
$ 23,471

21,629
(6,174)
(10,439)
4,553
786

1,466
(2,201)
(10)
3,234
4,202
(1,417)
15,629

14,530
(6,551)
10,606
6,074
67

606
(610)
(2,897)
2,096
(4,301)
2,009
21,629

16. Supplemental Quarterly Financial Information (unaudited)

Following is a summary of the unaudited interim results of operations for the years ended December 31, 2007 and 2006.

First Quarter

Second Quarter

2007
Third Quarter
(In millions, except per share amounts)

Fourth Quarter

Revenues

Earnings from continuing operations
Earnings from discontinued operations
Net earnings

Basic net earnings per common share:

Earnings from continuing operations
Earnings from discontinued operations
Net earnings

Diluted net earnings per common share:
Earnings from continuing operations
Earnings from discontinued operations
Net earnings

2,473

2,929

2,763

574
77
651

1.29
0.17
1.46

1.27
0.17
1.44

824
80
904

1.84
0.18
2.02

1.82
0.18
2.00

644
91
735

1.45
0.20
1.65

1.43
0.20
1.63

3,197

1,104
212
1,316

2.48
0.48
2.96

2.45
0.47
2.92

Full Year

11,362

3,146
460
3,606

7.05
1.03
8.08

6.97
1.03
8.00

107

Notes

Revenues

Earnings from continuing operations
Earnings (loss) from discontinued operations
Net earnings

Basic net earnings per common share:

Earnings from continuing operations
Earnings (loss) from discontinued operations
Net earnings

Diluted net earnings per common share:
Earnings from continuing operations
Earnings (loss) from discontinued operations
Net earnings

Earnings from Continuing Operations

First Quarter

Second Quarter

2006
Third Quarter
(In millions, except per share amounts)

Fourth Quarter

2,500

2,350

2,499

2,418

716
(16)
700

1.61
(0.03)
1.58

1.59
(0.03)
1.56

763
96
859

1.73
0.21
1.94

1.71
0.21
1.92

653
52
705

1.47
0.12
1.59

1.45
0.12
1.57

502
80
582

1.13
0.18
1.31

1.11
0.18
1.29

Full Year

9,767

2,634
212
2,846

5.94
0.48
6.42

5.87
0.47
6.34

The second quarter and fourth quarter of 2007 include a reduction to income tax expense from continuing operations of

$30 million (or $0.07 per diluted share) and $231 million (or $0.52 per diluted share), respectively, due to statutory rate
reductions in Canada.

The second quarter of 2006 included a reduction to income tax expense from continuing operations of $243 million (or

$0.55 per diluted share) due to statutory rate reductions in Canada and additional income tax expense of $39 million (or
$0.09 per diluted share) due to a new income-based tax enacted by the state of Texas.

The second and third quarters of 2006 include $16 million and $20 million, respectively, of reductions of carrying values

of oil and gas properties. The after-tax effects of these amounts were $16 million (or $0.04 per share) and $10 million (or
$0.02 per share), respectively.

Earnings from Discontinued Operations

The second quarter of 2007 earnings from discontinued operations includes a reduction of carrying value of oil and gas

properties of $64 million ($13 million after-tax) or $0.03 per diluted share.

The fourth quarter of 2007 earnings from discontinued operations includes a $90 million gain ($90 million after-tax) or

$0.20 per diluted share as a result of completing the sale of Devon’s Egyptian operations in October 2007.

Revenues for the first, second, third and fourth quarters of 2007 in the table above exclude $175 million, $215 million,

$206 million and $185 million, respectively, related to discontinued operations in West Africa and Egypt.

The first quarter of 2006 earnings from discontinued operations includes a reduction of carrying value of oil and gas

properties of $85 million ($85 million after-tax) or $0.19 per share.

Revenues for the first, second, third and fourth quarters of 2006 in the table above exclude $218 million, $267 million,

$223 million and $221 million, respectively, related to discontinued operations in West Africa and Egypt.

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 5, 2008, management concluded that its internal control over financial reporting was effective as of
December 31, 2007.

The effectiveness of Devon’s internal control over financial reporting as of December 31, 2007 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, 2007, as stated in their report, which is included on page 63.

108

Assumptions and Risks Related
to Forward-Looking Estimates

The forward-looking estimates beginning on page 56 are based on management’s examination of historical operating trends, the
information which was used to prepare the December 31, 2007, reserve reports and other data in Devon’s possession or available from
third parties. Devon cautions that its future oil, natural gas and NGL production, revenues and expenses are subject to all of the risks
and uncertainties normally incident to the exploration for and development, production and sale of oil, gas and NGLs. These risks
include, but are not limited to, price volatility, inflation or lack of availability of goods and services, environmental risks, drilling risks,
regulatory changes, the uncertainty inherent in estimating future oil and gas production or reserves, and other risks as outlined below.
The production, transportation, processing and marketing of oil, natural gas and NGLs are complex processes which are subject to
disruption due to transportation and processing availability, mechanical failure, human error, meteorological events including, but not
limited to, hurricanes, and numerous other factors.

Price Volatility

Prices for oil, natural gas and NGLs are determined primarily by prevailing market conditions. Market conditions for these

products are influenced by regional and worldwide economic conditions, weather and other local market conditions. These factors are
beyond Devon’s control and are difficult to predict. In addition to volatility in general, 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 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, Devon’s financial results and resources are highly influenced by price volatility.

Oil, Gas, and NGL Production

Estimates for future production of oil, natural gas and NGLs are based on the assumption that market demand and prices for oil,

gas and NGLs will continue at levels that allow for profitable production of these products. There can be no assurance of such stability.
Most of Devon’s Canadian production of oil, natural gas and NGLs is subject to government royalties that fluctuate with prices. Thus,
price fluctuations can affect reported production. Also, Devon’s international production of oil is governed by payout agreements with
the governments of the countries in which Devon operates. If the payout under these agreements is attained earlier than projected,
Devon’s net production and proved reserves in such areas could be reduced.

Marketing and Midstream

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

Foreign Exchange

Also, the financial results of Devon’s foreign operations are subject to currency exchange rate risks. Unless otherwise noted, all of
the dollar amounts are expressed in U.S. dollars. Amounts related to Canadian operations have been converted to U.S. dollars using a
projected average 2008 exchange rate of $0.98 U.S. dollar to $1.00 Canadian dollar. The actual 2008 exchange rate may vary materially
from this estimate. Such variations could have a material effect on our forward-looking estimates.

Property Acquisitions and Dispositions

Although Devon has completed several major property acquisitions and dispositions in recent years, these transactions are
opportunity driven. Except for the operations associated with the planned divestitures of Devon’s assets in West Africa, the forward-
looking estimates do not include the financial and operating effects of potential property acquisitions or divestitures during the year
2008.

Resource Potential

The United States Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only

proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally
producible under existing economic and operating conditions. This report may contain certain terms, such as resource potential, reserve
potential, probable reserves, possible reserves and exploration target size. The SEC guidelines strictly prohibit us from including these
terms in filings with the SEC.

109

Directors

John W. Nichols, 93, is a co-founder of
Devon. He was named chairman emeri-
tus in 1999. Nichols was chairman of the
board of directors from the time Devon
began operations in 1971 until 1999. He is a
founding partner of Blackwood & Nichols
Co., which put together the first public oil
and gas drilling fund ever registered with
the Securities and Exchange Commission.

Nichols is a non-practicing Certified Public Accountant.

J. Larry Nichols, 65, is a co-founder of
Devon and has been a director since 1971.
He was named chairman of the board of
directors in 2000 and serves as chair-
man of the Dividend Committee. Nichols
served as president from 1976 until 2003
and has been chief executive officer since
1980. Nichols serves as a director of Baker
Hughes Inc. and Sonic Corp. Nichols has a
Bachelor of Arts degree in Geology from Princeton University and
a law degree from the University of Michigan.

Thomas F. Ferguson, 71, joined the board
of directors in 1982 and serves as chairman
of the Audit Committee. Ferguson retired
in 2005 from his position as managing
director of United Gulf Management
Ltd., a wholly-owned subsidiary of Kuwait
Investment Projects Co. KSC. He has
represented Kuwait Investment Projects
Co. on the boards of various companies in

which it invests, including Baltic Transit Bank in Latvia and Tunis
International Bank in Tunisia. Ferguson is a Canadian qualified
Certified General Accountant and was formerly employed by the
Economist Intelligence Unit of London as a financial consultant.

David M. Gavrin, 73, joined the board of
directors in 1979 and is lead director and
chairman of the Compensation Commit-
tee. Gavrin has been a private investor
since 1989 and is a director and chairman
of the board of MetBank Holding Corp. He
is also president and a director of Arthur J.
Gavrin Foundation Inc. From 1978 to 1988,
he was a general partner of Windcrest

Partners, a private investment partnership in New York City, and,
for 14 years prior to that, he was an officer of Drexel Burnham
Lambert Inc.

David A. Hager, 51, joined the board of
directors in 2007. Hager served as chief
operating officer of Kerr-McGee Corp.
prior to its merger with Anadarko Petro-
leum Corp. in 2006. He has more than
25 years of oil and gas exploration and pro-
duction experience, including an extensive
background in planning and executing
deepwater exploration and development

projects. Hager also serves as a director of Pride International, Inc.

John A. Hill, 66, joined the board of direc-
tors in 2000 following Devon’s merger
with Santa Fe Snyder Corp. and serves
as chairman of the Governance Commit-
tee. He has been with First Reserve Corp.,
an oil and gas investment management
company, since 1983 and is currently its
vice chairman and managing director. Prior
to creating First Reserve Corp., Hill was

president and chief executive officer of several investment banking
and asset management companies and served as the deputy ad-
ministrator 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
director of various companies controlled by First Reserve Corp.

Robert L. Howard, 71, joined the board
of directors in 2003 and is chairman of
the Reserves Committee. Howard 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 Company and

McDermott International Inc.

William J. Johnson, 73, has been on the
board of directors since 1999. Johnson has
been a private consultant to the oil and
gas industry since 1994. 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 Corp. since 1996.
From 1991 to 1994, Johnson was president,

chief operating officer and a director of Apache Corp.

Michael M. Kanovsky, 59, joined the
board of directors in 1998. He was a co-
founder of Northstar Energy Corp. and
served on Northstar’s board of directors
from 1982 to 1998. Kanovsky is president
of Sky Energy Corporation and also serves
as a director of Accrete Energy Inc., ARC
Resources Ltd., Bonavista Petroleum Ltd.,
Pure Technologies Ltd. and TransAlta Corp.

J. Todd Mitchell, 49, joined the board of
directors in 2002. He currently serves as
president of Walton Mitchell & Co., Inc.,
a private energy investment company.
Mitchell served as president of GPM Inc.,
a family-owned investment company, from
1998 to 2006, and as vice president for
strategic planning from 2006 to 2007. He
was on the board of directors of Mitchell

Energy & Development Corp. from 1993 to 2002.

110

Mary P. Ricciardello, 52, joined the
board of directors in 2007. She retired in
2002 after a 20-year career with Reliant
Energy Inc., a leading independent power
producer and marketer. Ricciardello began
her career with Reliant in 1982 and served
in various financial management positions
with the company including comptroller,
vice president and most recently as senior

John Richels, 57, was elected president
of Devon in 2004 and joined the board of
directors in 2007. 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. Prior to joining Northstar, Richels

vice president and chief accounting officer. She serves on the
boards of U.S. Concrete and Noble Corp. and is a Certified Public
Accountant.

was managing and chief operating partner of the Canadian-based
national law firm, Bennett Jones. Richels previously served as a
director of a number of publicly traded companies. He holds a
bachelor’s degree in economics from York University and a law
degree from the University of Windsor.

Darryl G. Smette, 60, 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. His marketing background
includes 15 years with Energy Reserves
Group Inc./BHP Petroleum (Americas)
Inc. He 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.

Lyndon C. Taylor, 49, was elected to
the position of senior vice president and
general counsel in February 2007. Taylor
had served as Devon’s deputy general
counsel since August 2005. Prior to
joining Devon, Taylor was with Skadden,
Arps, Slate, Meagher & Flom, LLP for 20
years, most recently as managing partner
of the Houston office’s energy practice.

He is admitted to practice law in Oklahoma and Texas. Taylor
holds a Bachelor of Science degree in industrial engineering from
Oklahoma State University and a law degree from the University
of Oklahoma.

Senior Officers

Stephen J. Hadden, 53, was elected to the
position of senior vice president, Explo-
ration and Production, in 2004. In 1977,
Hadden joined Texaco, now Chevron Corp.,
as a field engineer, subsequently holding
a series of engineering and management
positions in the United States. In 2002, he
became an independent consultant.
Hadden received a Bachelor of Science

degree in chemical engineering from Pennsylvania State University.

Marian J. Moon, 57, was elected to the
position of senior vice president, Admin-
istration, in 1999. Moon is responsible
for office administration, information
technology, project management, records
management and corporate governance.
Moon has been with Devon for 24 years
and served in various capacities, including
manager of Corporate Finance and corpo-
rate secretary. Prior to joining Devon, Moon was employed by Am-
arex Inc., an Oklahoma City-based oil and natural gas production
and exploration firm, where her last position was treasurer. Moon
is a member of the Society of Corporate Secretaries & Governance
Professionals and a graduate of Valparaiso University.

Frank W. Rudolph, 50, was elected to the
position of senior vice president, Human
Resources, in June 2007. In the seven
years prior to joining Devon, Rudolph was
vice president Human Resources for Banta
Corporation, an international printing and
supply chain management company with
9,000 employees. His career in human
resources began at R. R. Donnelly & Sons

and spans more than 25 years. Rudolph has also held human
resources management positions at SANWA-Overhead Door
Corp., US West Communications, Clark Refining and Marketing,
Inc., James River Corporation and Tenneco Packaging. Rudolph
holds a Bachelor of Science degree in administration from Illinois
State University and a master’s degree in industrial relations and
management from Loyola University.

111

Glossary

Bitumen / A viscous, tar-like oil that requires
nonconventional production methods such as
mining or steam-assisted gravity drainage.

Independent producer / A non-integrated oil
and gas producer with no refining or retail
marketing operations.

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.

Deep water / In offshore areas, water depths of
greater than 600 feet.

Delineation 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.

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 the geographical location of its
first discovery and dominant rock type.

Fracture, refracture / The process of applying
hydraulic pressure to an oil or gas bearing
geological formation to crack the formation and
stimulate the release of oil and gas.

Gross acres / The total number of acres in which
one owns a working interest.

Hedge / A financial contract entered into to
manage commodity price risk.

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.

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.

London Inter Bank Offering Rate (LIBOR) /
An average of the interest rate on dollar-
denominated deposits, also known as
Eurodollars, traded between banks in London.

Natural gas liquids (NGLs) / Liquid
hydrocarbons 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.

New York Mercantile Exchange (NYMEX) / The
world’s largest physical commodity futures
exchange. The prices quoted for oil, gas and
other commodity transactions on the exchange
are the basis for prices paid throughout the
world.

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
committing significant capital to a large-scale
project.

Production / Natural resources, such as oil or
gas, taken out of the ground.

Gross production / Total production before
deducting royalties.

Net production / Gross production, minus
royalties, multiplied by one’s fractional

working interest.

Prospect / An area designated for the potential
drilling of development or exploratory wells.

Proved reserves / Estimates of oil, gas and
NGL quantities that, with reasonable certainty,
are thought to be recoverable from known
reservoirs under existing economic and
operating conditions.

Recompletion / The modification of an existing
well for the purpose of producing oil or gas
from a different producing formation.

Reservoir / A rock formation or trap containing
oil and/or natural gas.

Royalty / The owner’s share of the value of
minerals (oil and gas) produced on the property.

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.

Steam-assisted gravity drainage (SAGD) / A
method of extracting heavy oil from oil sands.
Steam is injected under ground, lowering the
viscosity of the heavy oil and allowing it to flow
to the surface.

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.

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

MMBbls / One million barrels

MBbld / One thousand barrels per day

Mcf / A standard measurement unit for
volumes of natural gas that equals one
thousand cubic feet.

MMcf / One million cubic feet

Bcf / One billion cubic feet

Tcf / One trillion cubic feet

MMcfd / One million cubic feet 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

MBoed / One thousand barrels of oil
equivalent per day

112

Shareholder Assistance
For information about transfer or exchange of
shares, dividends, address changes, account
consolidation, multiple mailings, lost certificates
and Form 1099:

Media
Chip Minty, Supervisor, External
Communications
Telephone: (405) 228-8647
E-mail: chip.minty@dvn.com

Computershare Trust Company, N.A.
PO Box 43078
Providence, RI 02940-3078
Toll free: (877) 860-5820
E-mail: web.queries@computershare.com

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

Shea Snyder, Assistant Manager,
Investor Relations
Telephone: (405) 552-4782
E-mail: shea.snyder@dvn.com

Scott Coody, Supervisor, Investor Relations
Telephone: (405) 552-4735
E-mail: scott.coody@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, Shareholder Services
Administrator
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 4,
2008, on the Third Floor of the Chase Tower,
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 16,000
shareholders of record.

This report was printed on certified recycled paper.

113

Forward-Looking Statements This annual report includes “forward-looking statements” as defined by securities law. Such statements are those concerning Devon’s plans, expectations and objectives for future operations including resource 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 forward-looking statements are reasonable. However, important risk factors could cause actual results to differ materially from the company’s expectations. A discussion of these risk factors can be found on page 109 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.Corporate HeadquartersDevon Energy Corporation20 North BroadwayOklahoma City, OK 73102-8260Telephone: (405) 235-3611Fax: (405) 552-4550Permian, Mid-Continent,Rocky Mountains andMarketing and Midstream OperationsDevon Energy Corporation20 North BroadwayOklahoma City, OK 73102-8260Telephone: (405) 235-3611Fax: (405) 552-4550Gulf, Gulf Coast and International OperationsDevon Energy CorporationDevon Energy Tower1200 Smith StreetHouston, TX 77002-4313Telephone: (713) 286-5700Canadian OperationsDevon Canada Corporation2000, 400 - 3rd Avenue S.W.Calgary, Alberta T2P 4H2Telephone: (403) 232-7100Royalty Owner AssistanceTelephone: (405) 228-4800E-mail: DevonRevenueHotline@dvn.com Common Stock Trading DataInvestor Information2006Quarter HigH Low Last totaL VoLumeFirst $ 69.97 55.30 61.17 253,074,600 Second $ 65.25 48.94 60.41 284,421,100 Third $ 74.75 57.19 63.15 338,019,000 Fourth $ 74.49 58.55 67.08 283,929,200 2007Quarter HigH Low Last totaL VoLumeFirst $ 71.24 62.80 69.22 267,618,540 Second $ 83.92 69.30 78.29 226,144,705 Third $ 85.20 69.01 83.20 217,392,650 Fourth $ 94.75 80.05 88.91 222,106,857 Certifications The Form 10-K which was filed by the company with the Securities and Exchange Commission (SEC) for the fiscal year ending December 31, 2007 includes as exhibits, the certifications of our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, required to be filed with the SEC pursuant to Section 302 of the Sarbanes Oxley Act of 2002. The company has also filed with the New York Stock Exchange the 2007 annual certification of its Chief Executive Officer confirming that the company has complied with the New York Stock Exchange corporate governance listing standards.Stock Performance – 5-Year Cumulative Total ReturnDollars60050040030020010002002 2003 2004 2005 2006 20076005004003002001000DevonS&P 500SIC Code(1)(1) Stock Index for Crude Petroleum and Natural GasCommitment Runs Deep