Devon Energy
Annual Report 2009

Pursuit with Purpose

Devon Energy     2009 Summary Annual Report

Volume Acronyms

Bbls / Barrels of oil. One barrel equals 
42 U.S. gallons.

  MBbls / Thousand barrels

  MMBbls / Million barrels

  MBbld / Thousand barrels per day

Mcf / A standard measurement unit for 
volumes of natural gas that equals 1,000 
cubic feet.

  MMcf / Million cubic feet

  Bcf / Billion cubic feet

  Tcf / Trillion cubic feet

  MMcfd / 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 6 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 / Thousand barrels of oil equivalent

  MMBoe / Million barrels of oil equivalent

  MBoed / Thousand barrels of oil  
  equivalent per day

Corporate Profile  
Devon Energy is a leading independent energy company 
engaged in the exploration, development and production of 
natural gas and oil. The company’s operations are focused 
onshore in the United States and Canada. Devon also owns 
natural gas pipelines and processing and treatment facilities in 
many of its producing areas, making it 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.

 
Pursuit with Purpose

Letter to Shareholders 
Chairman and CEO Larry Nichols reviews  
2009 and how Devon is pursuing the future.

Five-Year Highlights 

Purpose in Strategy 
Management answers investor questions.

Committed to Community 
We discuss our commitment to communities 
and environmental stewardship.

Pursuing Returns in North America 
Devon provides discussions of significant 
oil and gas properties.

11-Year Property Data 

Operating Statistics by Area 

Property Highlights 

Fracturing and Horizontal Drilling:  
Game Changing Technology 
Hydraulic fracturing, the process of pressuring 
water into wells to crack rock and stimulate 
production, is the technological key. 

Selected 11-Year Financial Data 

Consolidated Financial Statements 

Directors  

Senior Officers 

Investor Information and Stock Trading Data 

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1

Letter to Shareholders

Dear Fellow Shareholders:
We enter the new decade with excitement 
and anticipation. 2009 was a pivotal year 
for Devon as we embarked upon a strategic 
repositioning of the company. During the 
fourth quarter of 2009, we announced our 
plan to divest all of our Gulf of Mexico and 
international assets and to reshape Devon 
into an entirely North American onshore 
exploration and production company. 

Following the transformation, the 
company will be positioned to deliver 
strong organic growth throughout the 
inevitable ups and downs of commodity 
price cycles. Before we review the 
company’s challenges and achievements 
of 2009, I want you to understand the 
reasoning behind this seminal redirection 
of our company.

J. Larry Nichols
Chairman and Chief Executive Officer

2

Rewarding Resource Capture

Over much of the past decade, we 

sought to capture large-scale oil and 
natural gas resources onshore in the 
United States and Canada, offshore in the 
Gulf of Mexico and in select international 
regions. As one of the world’s largest 
independent exploration and production 
companies, it was necessary to target 
opportunities with sufficient size and 
scope to be meaningful. Our efforts 
to capture large-scale resources were 
rewarded, both onshore and off.

Onshore in North America, we 

established significant land positions 
in five exciting shale natural gas plays. 
After acquiring our initial interests in 
the Barnett Shale of north Texas in 
2002, Devon jump-started the shale-
gas revolution. We drilled the first-ever 
commercial horizontal shale wells 
and, to date, have drilled over 2,000 
successful horizontal wells in the Barnett. 
Leveraging the experience and the 
expertise we gained in the Barnett, we 
then expanded our shale arsenal into the 
Arkoma-Woodford, Cana-Woodford and 
Haynesville plays in the United States 
and into Canada’s Horn River play in 
British Columbia. Devon’s combined net 
risked resource potential in these five 
shale plays exceeds 40 trillion cubic feet 
of gas equivalent—nearly three times the 
size of our entire current proved reserve 
base.

In addition to our success onshore, 
between 2002 and 2006 we made four 
significant oil discoveries in the deepwater 
Lower Tertiary trend of the Gulf of Mexico. 
In conjunction with our four Lower Tertiary 
discoveries, we also assembled one of 
the largest deepwater lease and prospect 
inventories in the Gulf. Our Lower Tertiary 
holdings alone encompass more than 
800,000 acres under approximately 140 
federal lease blocks. 

Devon also assembled a valuable 

asset base offshore Brazil, including the 
Polvo oil field and two significant oil 
discoveries in the Campos Basin that await 
development. Offshore Brazil is home to 
some of the largest oil discoveries of this 
new century. Furthermore, recent changes 
to leasing rules enacted by the Brazilian 
government make it nearly impossible 
today to replicate our asset portfolio in 
Brazil. 

Indeed, we were very successful in 

capturing potential oil and gas resources. 
However, all of this success presented us 
with a paradox: we had more high-quality 
development opportunities than we could 
simultaneously pursue. Therefore, in 
order to optimize the value of our overall 
opportunity set, we are relinquishing 
some opportunities and focusing our 
resources on others. This led to our 
decision to monetize our Gulf of Mexico 
and international assets and to focus 
our capital and human resources on our 
world-class assets onshore in the U.S. and 
Canada.

Devon is also the first U.S.-based 

independent producer to construct and 
operate a steam-assisted gravity drainage 
project in Canada. Production from our 
Jackfish SAGD project in Alberta is now 
approaching the 35,000 barrel per day 
facilities’ capacity and is proving to be 
one of the most successful projects in 
this segment of the industry. Production 
per well and energy input per barrel 
produced rank Jackfish among the best 
steam assisted gravity drainage projects. 
Following the success of our first phase 
of Jackfish, we are doubling the project 
with construction of Jackfish 2, slated to 
become operational in 2011. In addition, 
we have completed our geologic 
evaluation and plan to file a regulatory 
application in 2010 for a third 35,000 
barrel per day phase of Jackfish. To 
further leverage our SAGD expertise, in 
March of 2010, we signed an agreement 
with BP to form a joint venture in 
which Devon will acquire 50% of BP’s 
interest in the Kirby oil sands leases. 
While additional evaluation is needed to 
determine the final development plan for 
Kirby, these leases have similar geology, 
reservoir characteristics and oil quality 
to that of our Jackfish complex located 
just to the north. Based on the limited 
portion of the Kirby leases upon which 
we currently have data, we expect Kirby 
to yield a multi-stage SAGD development 
with total recoverable resources of up 
to 1.5 billion barrels. As we evaluate 
additional parts of this large land 
position, we hope to uncover additional 
resource potential. For a more in-depth 
review of our North American onshore 
assets, see pages 10-18 of this 2009 
annual report.

Accelerating Value Realization

The strategic repositioning is well 

underway. As I write this letter, we have 
signed sales agreements totaling $8.3 
billion. Assuming reasonable sales prices 
for the remaining divestiture assets, we 
now expect total after-tax proceeds from 
the divestiture process to exceed the 
top end of our forecasted range of $4.5 
billion to $7.5 billion. Many prospective 
buyers have visited our data rooms for the 
remaining properties. We will thoroughly 
evaluate the bids and accept those that 
maximize value. The entire process should 
be completed before year end.   

The sales proceeds from these 
transactions present Devon with many 
options. We are deploying a portion to 
jump-start our production growth across 
our North American onshore property 
base and will initially utilize the remaining 
proceeds to retire debt. In anticipation 
of receipt of the offshore sales proceeds, 
we began to allocate additional capital 
to onshore projects in the fourth quarter 
of 2009. However, should rising industry 
costs or a deteriorating outlook for oil or 
natural gas prices challenge the economics 
of any of our projects, we will do what we 
have done in the past. We will curtail our 
activity levels and preserve our resources 
until industry conditions improve.    

Following the repositioning, Devon 
will have a rock-solid balance sheet. We 
also expect to achieve additional cost 
savings, resulting in lower lease operating, 
general and administrative and interest 
expenses. The repositioned Devon will 
have the capacity to deliver significant 
organic growth without the need to issue 
additional debt or equity.  We will be 
situated for fierce competition—as one of 
the strongest exploration and production 
companies in North America. 

3

In closing, I would like to bid a 
sincere farewell to two retiring members 
of our board of directors. Tom Ferguson 
has served for nearly 30 years, and 
his contributions, including serving 
as chairman of the Audit Committee, 
are immeasurable. Bob Howard joined 
our board following the 2003 Ocean 
Energy merger and has faithfully served 
as chairman of the Compensation 
Committee. Bob’s many years of 
industry experience made him a valuable 
contributor. Devon is grateful for the 
years of service and expertise provided 
by these gentlemen. Each of them has 
provided valuable leadership, and their 
contributions to the company’s success 
are deeply appreciated.  

J. Larry Nichols
Chairman and Chief Executive Officer
March 24, 2010

2009 Remembered

The fallout from the financial 

crisis that began in 2008 resulted in 
extreme oil and gas price volatility in 
2009. Though oil prices strengthened 
throughout 2009, they still averaged 
about 40% less than in 2008. Natural gas 
prices trended lower for much of 2009 
and averaged less than half of what they 
were in 2008.

the drill bit—more than 200% of our 
North American onshore production 
for the year. Including proved reserve 
additions resulting from price changes, 
we replaced more than three times our 
annual production. With related capital 
costs of only $3.3 billion, we added North 
American onshore reserves at a cost per 
barrel among the lowest in our industry.

Low oil and gas prices at the end 

Looking Beyond 2010

of the first quarter 2009 triggered a 
non-cash adjustment to the carrying 
value of Devon’s oil and gas properties. 
This charge resulted in a net loss of $2.5 
billion for the full year. Cash flow from 
operations declined by approximately 
50% compared with 2008. However, 
production growth from our North 
American onshore properties, as well 
as solid results from our marketing and 
midstream operations, allowed us to 
generate cash flow from operations that 
still topped $4 billion for the full year.
Due to deteriorating market 

conditions, we significantly cut 
capital spending in 2009 and drilled 
less than half of the number of wells 
drilled in 2008. Nonetheless, we grew 
production in our North American 
onshore business by 6%, to 220 million 
oil-equivalent barrels. Furthermore, the 
1,100-plus successful wells we drilled 
during 2009 contributed to impressive 
reserve additions. Excluding revisions 
attributable to price changes, we added 
492 million oil-equivalent barrels with 

The year 2010 will be one of 
transition as we complete the Gulf and 
international divestitures, accelerate 
North American onshore activity and 
refocus our workforce. As we emerge 
from this transformation, Devon has 
captured all the attributes necessary to 
realize our vision of being the premier 
independent oil and gas company in 
North America. We have established 
many years of growth opportunities in 
some of the best oil and gas plays in 
North America. We have industry-leading 
technical expertise to apply to these 
opportunities. We have the scale and 
resolve to maintain a highly competitive 
overall cost structure.  And upon closing 
the property divestitures for which we 
have already executed contracts, we will 
emerge with one of the strongest balance 
sheets among U.S. independents.

Looking ahead, I could not be more 

excited about Devon’s future. While 
we faced some difficult decisions in 
2009, we acted decisively. We could 
not be in the enviable position for the 
future that we find ourselves today 
without the commitment and support 
of Devon’s talented and dedicated 
team of employees. That support was 
acknowledged as Devon was named the 
top ranked energy company by Fortune 
magazine’s “100 Best Companies to 
Work For.”  This award is driven largely 
by feedback from our employees.  I thank 
each and every one of them for sharing in 
our success.    

4

Five-Year Highlights

YeAR eNDeD DeCemBeR 31,  

2005 

2006 

2007 

2008 

2009 

LAST YeAR (1)
CHANGe

Financial Data (Millions, except per share data)
  Revenues 
  Total expenses and other income, net (2) (3) 
  Earnings (loss) from continuing operations before income taxes 
  Total income tax expense (benefit) 
  Earnings (loss) from continuing operations 
  Earnings from discontinued operations 
  Net earnings (loss) 
  Net earnings (loss) applicable to common stockholders  

  Net earnings (loss) 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 
  Long-term debt 
  Stockholders’ equity 
  Working capital (deficit) 

$ 

$ 

$ 
$ 

$ 

$ 
$ 

$ 
$ 
$ 
$ 

 9,630  
 5,477  
 4,153  
 1,413  
 2,740  
 190  
 2,930  
 2,920  

 9,143  
 5,957  
 3,186  
 870  
 2,316  
 530  
 2,846  
 2,836  

 9,975  
 6,648  
 3,327  
 842  
 2,485  
 1,121  
 3,606  
 3,596  

 13,858  
 18,018  
 (4,160) 
 (1,121) 
 (3,039) 
 891  
 (2,148) 
 (2,153) 

 8,015  
 12,541  
 (4,526) 
 (1,773) 
 (2,753) 
 274  
 (2,479) 
 (2,479) 

 6.38  
 6.26  

 6.42  
 6.34  

 8.08  
 8.00  

 (4.85) 
 (4.85) 

 (5.58) 
 (5.58) 

 458  
 470  

 442  
 448  

 445  
 450  

 444  
 444  

 444  
 444  

 (42%)
 (30%)
(9%)
(58%)
 9%
 (69%)
(15%)
(15%)

15%
15%

0%
0%

 5,612  

 5,993  

 6,651  

 9,408  

 4,737  

 (50%)

0.30 
62.54 

0.45 
67.08 

0.56 
88.91 

0.64 
65.71 

0.64 
73.50 

0%
12%

2005 

2006 

2007 

2008 

2009 

LAST YeAR (1)
CHANGe

 30,273  
 5,957  
 14,862  
 1,272  

 35,063  
 5,568  
 17,442  
 (1,433) 

 41,456  
 6,924  
 22,006  
 257  

 31,908  
 5,661  
 17,060  
 (451) 

 29,686  
 5,847  
 15,570  
 (810) 

 (7%)
3%
 (9%)
(80%)

YeAR eNDeD DeCemBeR 31,  

2005 

2006 

2007 

2008 

2009 

LAST YeAR (1)
CHANGe

Property Data (4)
  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)  

426  
7,170  
246  
1,868  

38 
816 
24 
198 

499  
8,251  
275  
2,149  

32 
807 
23 
190 

558  
8,987  
321  
2,376  

35 
862 
26 
204 

301  
9,879  
352  
2,299  

39 
938 
28 
223 

686  
9,757  
421  
2,733  

128%
 (1%)
20%
19%

42 
966 
30 
233 

8%
3%
7%
4%

(1)  All percentage changes in this table are based on actual figures and not the rounded numbers shown.
(2) 
(3) 
(4)  Excludes results from discontinued operations.

Includes other income, which is netted against other expenses.
Includes non-cash charges resulting from full-cost ceiling adjustments in 2008 and 2009 of $9,891 million and $6,408 million, respectively.

5

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
Purpose in Strategy

Management Answers Investor Questions

Do you have a specific plan in place for deployment of 
the proceeds of the Gulf of mexico and international 
divestiture proceeds?

Due to better-than-expected proceeds to date, we now 

estimate the after-tax proceeds of the Gulf of Mexico and 
international divestitures to be between $7.5 billion and $8.3 
billion. We have earmarked $3.5 billion for eliminating our 
commercial paper balances and upcoming maturities of long-
term debt. In addition, we will spend $500 million to purchase 
half of BP’s interest in the Kirby oil sands leases. We will allocate 
the remaining proceeds between incremental investments, 
share repurchases and additional debt reduction based on 
market conditions at the time we receive the proceeds. We will 
seek the balance between these alternatives that maximizes our 
per share growth over the long run.

Why has Devon chosen to adopt a more aggressive 
hedging strategy?

Over the last two years our industry experienced a sobering 

reminder of just how volatile natural gas and oil prices can be. 
Within a period of only months, we saw both natural gas and 
oil prices decline by more than two-thirds. Then, just as quickly, 
oil prices more than doubled from their lows, yet natural gas 
prices remained stubbornly weak. Such heightened volatility, 
amplified by a decoupling of oil and gas prices, has made 
capital budgeting and investment planning more challenging. 
Furthermore, moving activity levels rapidly up and down in 
response to variations in cash flow is inefficient. 

Our decision to protect the prices of roughly half of our 

expected production of both natural gas and oil is intended to 
smooth out the effects of price volatility and make our available 
cash flow more predictable. For 2010, we have locked in the 
price of about half of our forecasted natural gas production 
and almost two-thirds of our forecasted oil production. This 
has given us a much higher degree of confidence in the level of 
internally generated cash flow.

What is Devon’s long-term outlook for natural gas prices?

There are many factors to consider when forecasting prices, 

and none of those variables can be predicted with certainty. 
Demand for natural gas will depend in large part upon how 
quickly and how strongly the U.S. and world economies improve. 

Gas supply is dependent upon the level of drilling for new 

gas wells, the production rates of the new wells and how quickly 
these wells decline in production. In recent years, average 
production per well has increased with the improved efficiency 
of horizontal drilling and the discovery of shale plays that yield 
very high initial production rates. However, the production from 
these wells also declines more rapidly than production from 
conventional natural gas wells. While rig utilization levels have 
increased recently, the number of rigs now drilling for natural gas 
in North America is almost 40% less than the level of the recent 
peak in 2008. 

This suggests that supply and demand for natural gas 
will rebalance over time. Does this mean 2010 will be a good 
year for gas prices? That is unlikely. But we do believe that 
longer term, the relationship between natural gas prices and 
industry costs must return to levels that will enable the most 
efficient producers, like Devon, to generate a healthy return on 
investment. 

With all the shale gas now hitting the market, natural gas 
prices have suffered. Have you decided to focus on North 
American gas at the wrong time?

The decision to divest our Gulf of Mexico and international 

assets does reposition Devon as a North American onshore 
company but not as a significantly more gas-focused company. 
Following the divestitures, our balance between natural gas 
and liquids will remain largely unchanged at roughly two-thirds 
gas and one-third liquids. Furthermore, as a part of our recent 
agreement with BP to sell them a portion of our deepwater 
Gulf of Mexico and international assets, we were able to gain 
access to half of BP’s interest in their Kirby oil sands leases. Kirby 
is located directly adjacent to our highly-successful Jackfish 
project and provides Devon with the opportunity to grow our 
oil production from this region for many years. We have also 

6

established a significant undeveloped acreage position in the 
highly-economic Wolfberry play in the Permian Basin of west 
Texas. We plan to ultimately drill more than 1,000 Wolfberry 
wells on our existing acreage. In addition, Devon is exploring for 
new oil opportunities both inside and outside our massive land 
holdings in the U.S. and Canada. We believe that our continued 
investment in oil projects such as Jackfish, Kirby and Wolfberry, 
coupled with our exploration for new oil plays in North America, 
provides a solid platform from which we can increase oil 
production.

It is also important to note that, should natural gas prices 
be in an extended period of weakness, the repositioned Devon 
stands to fare very well. We have large, high-quality positions in 
many of the best natural gas plays in North America. As an early 
mover in these plays, we have established our positions with low 
entry costs and low average royalty burdens. We have the scale, 
technical expertise and balance sheet strength that prepare 
us to compete successfully against anyone in this arena. In 
addition, we have a balance between natural gas and liquids that 
stabilizes our revenue stream in environments like the current 
one, with relatively high oil prices and relatively low gas prices.  
Should hard times hit the North American natural gas business, 
Devon is positioned for success.    

After completion of the Gulf of mexico and international 
divestitures, you will have a very strong balance sheet 
and abundant cash. Could that lead to acquisitions?

It is difficult to imagine a situation that would lead Devon 
to pursue large-scale corporate acquisitions. A primary reason 
for divesting our Gulf and international assets is our very deep 
inventory of opportunities in North America. The same strong 
belief in our existing North American onshore asset base that 
led to our current restructuring has left us without the need to 
pursue large-scale acquisitions in recent years. We have grown 
production organically from our onshore assets at an average 
annual rate of 9% since 2006. This production growth has been 
supported by strong reserve growth at very competitive costs.  
Our existing North American onshore assets comprise millions 
of acres of prospective lands encompassing more than 32,000 
undrilled locations. This represents many years of potential 
growth without the need for acquisitions. Given the depth and 
quality of our existing asset base, if Devon were to become more 
acquisitive, the most likely acquisition would be that of Devon’s 
own stock. 

Devon’s production from the Barnett Shale began to 
decline in 2009. Can you resume growth in the Barnett 
again?

As the worldwide recession broadened in 2008 and oil and 

natural gas prices fell, we reduced drilling activity companywide. 
In the Barnett Shale we reduced the number of drilling rigs 
operated by Devon by more than 75%. By mid-2009, our reduced 
Barnett drilling program was not sufficient to sustain production 
growth. Having reached 1.2 billion cubic feet of gas equivalent 
per day early in 2009, we exited last year producing less than 1.1 
billion cubic feet equivalent per day. Now in early 2010, we are in 
the process of reversing that trend by adding to our operated rig 
count in the Barnett Shale, and we plan to drill about 370 Barnett 
wells in the year. At this level of drilling, we expect to restore our 
Barnett production to about 1.2 billion cubic feet equivalent per 
day in the third quarter of 2010. Further production growth from 
the Barnett Shale will depend upon how much capital we choose 
to allocate to the area. However, with more than 4,000 producing 
wells and 7,000 undrilled locations in inventory, the Barnett Shale 
will likely remain Devon’s most significant producing property for 
many years to come.

How do you answer critics who say that natural gas from 
shale may not live up to its high expectations?

Some detractors are saying that North American shale gas 

plays—such as the Barnett, Haynesville and Marcellus—may 
prove to be less productive or have less attractive economics 
than is now believed to be true. In reality, it is very difficult to 
generalize about the economics and productivity of any oil or 
gas play, including these new shale plays. Just as we have seen in 
the Barnett, these plays are not homogeneous across the entire 
play area. Geology, drilling costs and above-ground challenges 
all vary across these plays. In addition, even within similar areas, 
economic returns vary from company to company depending 
upon what a company paid to lease the acreage and the contract 
terms of their leases. We are confident that companies such as 
Devon, with the lowest entry costs and best acreage positions, will 
continue to deliver good rates of return from these shale plays.

Evidence is building that the future for shale gas resources is 

very bright. Devon’s experience in the Barnett Shale is a case in 
point. Since acquiring our initial interests in the Barnett in 2002, 
we have increased production and proved reserves every year. 
And during that period we have produced more than 2.1 trillion 
cubic feet of gas equivalent from the play. Devon’s leadership 
in the Barnett has helped drive the Barnett to be the largest 
producing gas field in the nation. 

Another example in Devon’s portfolio is the Cana-Woodford 

Shale play in Oklahoma, we began drilling just a few years ago, 
and we are already seeing many similarities between the Cana 
and the Barnett. Typical well results continue to improve, and we 
have increased field-wide reserves by 260% and production by 
465% since 2008. 

Based on Devon’s successes in the Barnett, Cana-Woodford 

and other shale plays, the ability of shale gas to play an 
important role in North America’s energy future should not be 
underestimated.

7

Committed to Community

Being a good neighbor is important to us, 
and we believe it is important to the long-
term success of our company. Healthy 
communities help companies grow. This is 
why we support community projects, civic 
initiatives and education. It is why we look 
for ways to conserve water, restore habitat 
and reduce emissions.

Supporting our Neighbors

The partnership we establish with our 

neighbors is an investment in our future. 
That is why we are strong supporters of 
public education and emergency service 
organizations as well as the arts, civic 
organizations and volunteerism.

Devon’s Science Giants Award for 
public schools in Houston and Oklahoma 
City illustrates our effort to contribute 
to a better quality of life in communities 
where we do business. Devon established 
the Science Giants Award in 2007 to 
recognize and encourage outstanding 
science programs. Through this award 
program, we can call attention to the 
importance of science education as a 
critical need in our company and our 
industry.

In addition to science in public 

schools, Devon supports science, 
engineering and research on college 
campuses. The University of Oklahoma 
opened Devon Energy Hall in January 
2010, providing state-of-the-art teaching 
and research space for the school’s college 
of engineering. Devon has also helped 
Oklahoma State University develop new 
geology teaching facilities, funded a 

8

new petroleum engineering program at 
the University of Houston and supported 
research and internship programs at 
a variety of universities across North 
America.

Devon’s employees make an impact 

on the lives of individual students through 
tutoring and mentoring programs in 
Oklahoma City, Houston and elsewhere. 
Hundreds of Devon employees take time 
each week to tutor students in reading and 
math.

Devon volunteers also give time 
to civic initiatives such as Habitat for 
Humanity and community efforts such 
as the annual Oklahoma City Memorial 
Marathon where more than 100 volunteers 
man a water stop. 

Devon enlists the aid of its own 

field personnel as well as others in the 
community through the company’s 
Wise Eyes crime watch program. Devon 
initiated the program in Wise County, 
Texas, to establish communication links 
between the sheriff’s office and hundreds 
of field personnel who travel county roads 
every day. With all of those eyes and ears 
watching and listening, suspicious activity 
is more likely to be noticed and reported. 
As a result of our success in Wise County, 
we have helped launch 30 similar Wise 
Eyes programs in five states where we do 
business.

Devon representatives surprise a Houston elementary school with a $25,000 grant to help fund science education initiatives.In addition to education and public 

safety initiatives, Devon supports the 
arts through a variety of contributions 
to community organizations. Devon 
provides funding for museums in Calgary, 
Fort Worth, Houston and Oklahoma City. 
The company also is a major contributor 
to the performing arts. For example, 
Devon’s support for the Oklahoma City 
Philharmonic and Ballet Oklahoma 
enhances the quality of performances for 
patrons across the community. Devon 
also funds a special program that allows 
Oklahoma City’s Lyric Theater to provide 
interactive musicals to rural communities 
where other opportunities to see live 
performances are limited.

Reducing emissions   

By reducing the volume of our 
natural gas emissions, we contribute to a 
cleaner environment and deliver greater 
value to shareholders. We have turned to 
new technology and innovative practices 
to keep more of our natural gas and 
natural gas liquids in the pipeline.

By investing extra effort and by using 

the latest technology, we have reduced 
our emissions in the United States and 
Canada in each of the past 15 years. In 
2008, for example, Devon’s companywide 
emissions reductions dropped by 16% 
from the previous year. 

Our Role

Through these programs, we 

contribute to the prosperity of 
communities that surround us, and we 
make a meaningful contribution to the 
protection of our environment. These 
efforts also make good business sense. 

Being a good neighbor is one of our 

corporate values because it is the right 
thing to do. It is good for our employees 
and their families. It is good for those who 
live and work around us. And it lays the 
groundwork for our success as a company. 

A large portion of those reductions 
have come through our use of a procedure 
we call “green completions” in the Barnett 
and other shale natural gas fields. While 
conventional completion methods 
permit natural gas to be vented into the 
atmosphere, green completions allow 
us to capture that gas and move it into 
our pipelines. Through this process we 
capture an average of 3 million cubic feet 
of additional natural gas per well. Without 
green completions, that would be lost 
to the atmosphere. At today’s market 
prices, that represents about $15,000 
in additional revenue per well. From an 
environmental perspective, each green 
completion is equivalent to taking 267 cars 
off the road for a year. Since 2004, green 
completions have allowed us to reduce 
our methane emissions by nearly 13 billion 
cubic feet.

For more information on Corporate Responsibility: 
www.devonenergy.com/CorpResp/initiatives/Pages/featurestories.aspx
• Devon’s commitment to emission reduction

9

Pursuing Returns in North America

Since the beginning of the last decade 
Devon has focused on resource capture. We 
pioneered horizontal drilling in shale, and 
we became adept at steam-assisted gravity 
drainage in the Alberta oil sands. We also 
began exploring in the deepwater Gulf of 
Mexico and offshore Brazil. 

A demethanizer tower is installed 
at Devon’s 200 million cubic feet 
per day gas processing plant in the 
Cana-Woodford Shale. By owning and 
operating gas processing facilities, 
Devon can improve its operating 
efficiency.

Fast forward to the present, Devon 

has industry-leading positions in five 
natural gas shale plays, top decile SAGD 
projects and an extensive exploration 
and development position in both the 
Gulf of Mexico and offshore Brazil. 
However, our success has led to an 
overabundance of opportunities. As 
a result, in late 2009, we announced 
plans to divest all of our Gulf of Mexico 
and international assets and to focus 
our operations exclusively on our lower 
risk, higher return U.S. and Canadian 
onshore operations. The following 
profiles are of some of the company’s 
more significant onshore properties.

10

Oil Sands Success

Oil and natural gas liquids 

production are important contributors 
to Devon’s production and revenue 
streams. Our highest-profile oil project 
is the Jackfish oil sands development in 
Alberta. The oil sands of western Canada 
have been called the Saudi Arabia 
of North America, and Devon holds 
interests in over 150,000 acres of rich oil 
sands leases. 

Devon was the first U.S.-based 
independent energy company to develop 
and operate an oil sands project in 
Canada. We began construction of the 
first phase of the Jackfish development 
along with a 200-mile transportation 
pipeline in 2005. Production commenced 
in 2007 and approached plant capacity of 
35,000 barrels of oil per day in 2009. 
Jackfish uses the steam-assisted 
gravity drainage method of production. 
SAGD is similar to conventional oil 
and gas drilling, with far less surface 
disturbance than that associated with 
oil sands mining projects. In SAGD 
projects, steam is piped underground to 
heat and release the oil trapped below. 
The efficiency of Jackfish, as measured 
by steam requirements and production 
per well, make it one of Canada’s most 
successful SAGD projects to date.
The outstanding results from 

Jackfish and successful stratigraphic tests 
encouraged Devon to double its size by 
launching a second phase of the project. 
We commenced construction of Jackfish 
2 in 2008, with first production planned 
for 2011. A third phase of Jackfish is now 
in the planning stages, with regulatory 
filing expected in 2010. In aggregate, the 
three phases will recover an estimated 
900 million barrels of oil and will 
generate gross production of more than 
100,000 barrels per day.

To build on our success at Jackfish 

and to leverage our expertise as a SAGD 
operator, in March 2010 we announced 
plans to form a joint venture with BP 
in which Devon is purchasing 50% 
of BP’s interest in the Kirby oil sands 
leases. The Kirby acreage is located 
just south of our Jackfish position and 
represents another multi-stage SAGD 
development opportunity. Development 
of the Kirby leases is still in its infancy, 
and there is significant evaluation work 
to be done over the next few years to 
fully delineate the resource and finalize 
the development plan. However, we 
already have considerable well control 
and seismic data that indicate similar 
geology, reservoir characteristics and 
oil quality to that of Jackfish. In fact, we 
believe Kirby holds even more potential 
than Jackfish with up to 1.5 billion barrels 
of gross recoverable resource.

Barnett: First Among Shales

The Barnett Shale natural gas field in 

north Texas kicked off a shale gas boom 
that has fundamentally changed how the 
United States views its energy future. 
Before discovery of the Barnett and other 
shale plays that followed, the outlook for 
increasing domestic energy production 
was dim. Driven by the success of 
horizontal drilling in shale—pioneered by 
Devon in the Barnett—vast new sources 
of domestic, environmentally friendly, 
clean-burning natural gas are within 
reach.  

The apparent abundance of new 
shale gas resources, coupled with its 
environmental advantages, make natural 
gas a viable bridge to a more sustainable 
energy future. With significant ownership 
in five important plays, Devon is a leader 
in the shale-gas revolution.

The Barnett Shale is the most 
important North American gas shale 
to date and is Devon’s largest single 
asset. When our Gulf and international 
divestitures are complete, the Barnett 
Shale will represent about 40% of 
Devon’s retained proved reserves and 
about 30% of our daily production. 
Devon’s Barnett production averaged 1.1 

billion cubic feet of gas equivalent per 
day in 2009.

With about 663,000 net acres, 

Devon holds the best position of any 
producer in the Barnett Shale. More 
than 90% of our acreage lies in the most 
productive parts of the play. As the first 
entrant in the Barnett, Devon paid less 
for its acreage and retained a larger 
share of revenue than companies that 
bought in later. Our average lease cost 
is only $2,800 per acre with an average 
royalty burden of 18%. For comparison, at 
the height of the Barnett leasing frenzy 
in 2007 and 2008, lease costs of $25,000 
and more per acre and royalties of 25% 
and greater were common.

While production from the Barnett 

has peaked for many companies 
operating there, Devon’s has not. Our 
vast acreage position represents an 
inventory of more than 7,000 additional 
drilling locations. Even at very high 
activity levels, this represents many 
years of additional growth opportunities. 
Natural gas prices and overall portfolio 
management considerations will 
influence how quickly we elect to drill 
these locations. However, regardless 
of the pace of new drilling, the Barnett 
Shale will remain a core component of 
Devon’s producing portfolio far into the 
future.

Capturing Cana

Another of Devon’s shale-gas gems 

is the emerging Cana-Woodford Shale 
in central Oklahoma. Encouraged by 
geological and geographical similarities 
to the Barnett and the Arkoma-Woodford 
play in eastern Oklahoma, Devon began 
in 2006 to acquire acreage in the Cana 
play. As an early mover in the Cana, we 
were able to assemble a significant lease 
position at a relatively low cost. Devon’s 
118,000 net acres in the play represent 
a large portion of what we believe will 
be the most productive part of the play. 
Our average lease cost in the Cana was 
only $2,200 per acre with an attractive 
average royalty burden of 21%.

11

Although, at 11,500 feet to 14,500 

feet, the Cana-Woodford shale is deeper 
than the Barnett, with estimated per-
well recoveries of around 8 billion cubic 
feet of gas equivalent, these wells yield 
attractive rates of return. Much of the 
Cana gas is also liquids-rich, like portions 
of the Barnett, further enhancing 
economics.

Devon’s net production from the 
Cana-Woodford climbed to 39 million 
cubic feet equivalent per day in 2009, a 
465% increase over 2008 production. To 
assure sufficient capacity for our rapidly 
growing Cana-Woodford production, we 
are now constructing a gas processing 
plant. The plant, which will be completed 
early in 2011, is initially sized to handle 
200 million cubic feet of gas per day 
and can be expanded as field production 
grows. We plan to drill about 80 wells 
at Cana in 2010 in a program intended 
to de-risk the play and to secure our 
valuable acreage by establishing 
production.

Haynesville De-Risking Under Way
The Haynesville Shale play 

encompasses a large geographic area in 
eastern Texas and northern Louisiana, 
and Devon holds extensive acreage 
in both states. In 2009, we began to 
methodically de-risk parts of our leases 
in Texas. We began with 110,000 net 
acres in the greater Carthage area of east 
Texas, which includes parts of Harrison, 
Panola and Shelby counties.

To date, Devon has drilled almost 

a dozen Haynesville horizontal wells 
on our Carthage leases achieving solid, 
repeatable results. We now expect our 
greater Carthage acreage to support 
more than 1,000 wells. As with the 
Barnett and Cana-Woodford plays, Devon 
acquired its Carthage area leases at very 
attractive costs and at an average royalty 

burden of only 19%. In 2010 we expect to 
drill 11 additional Haynesville Shale wells 
on our Carthage area leases. 

To the south of Carthage, Devon 

holds 47,000 net acres primarily in 
Nacogdoches, San Augustine and Sabine 
counties in Texas and in Sabine Parish, 
Louisiana. We are in the very early stages 
of drilling and de-risking this southern 
Haynesville acreage. In 2010 we expect 
to drill about 50 wells (14 net wells) in the 
area as we work to secure acreage.

In addition to the potential in the 

Haynesville shale formation, portions of 
our acreage in the greater Carthage and 
southern areas also have Bossier Shale 
potential. In 2010 we expect to drill our 
first wells targeting the Bossier Shale to 
evaluate the quality of this formation 
under our acreage. 

Arkoma-Woodford Poised for Growth
Devon’s 58,000 net acres in the 

Arkoma-Woodford Shale play are 
concentrated in Coal and Hughes 
counties in Oklahoma. After securing 
this acreage at an average cost of only 
$400 per acre, we drilled our first wells 
in the play in 2005. We have now drilled 
325 producing wells in the Arkoma-
Woodford, driving Devon’s share of 
production to approximately 70 million 
gas-equivalent cubic feet per day at the 
end of 2009.

In 2010 we plan to continue our 

production growth in the Arkoma-
Woodford, drilling 85 wells compared 
with 61 wells drilled in 2009. With an 
estimated 2,150 remaining drilling 
locations on Devon’s leases, we have 
the capacity to increase drilling activity 
rapidly when we choose to do so.

12

Horn River Rising

The Horn River Basin shale play, 

located in the northern reaches of 
British Columbia, is in the early stages 
of development. Devon has acquired 
170,000 net acres in the best parts of 
the Basin and has successfully begun 
de-risking our acreage through the 
drilling of horizontal pilot wells and 
vertical stratigraphic test wells.

Although located in a remote area, 
Devon is working to expand the existing 
gas gathering system infrastructure and 
has taken a 26.7% working interest in the 
new 400 million cubic feet per day Cabin 
Gas Plant. The Cabin Plant is currently 
under construction and is expected to 
be on-stream in 2012. Newly developed 
all-season roads and expanding service 
industry infrastructure are allowing 
operations to continue year-round.
Gas content in the Horn River 
shale is estimated at 150 billion to 300 
billion cubic feet per square mile. This is 
greater on average than gas content in 
the Barnett Shale but at similar geologic 
depths. The combination of abundant gas 
in place and relatively shallow drilling 

A shale gas well is drilled in the Horn River Basin 
in northern British Columbia. Devon has nearly 
10 trillion cubic feet of net resource potential in 
the Horn River Basin representing some 1,600 
drilling locations.

offers the potential for results as good as 
or better than the Barnett.

Government-issued leases in British 

Columbia have relatively lengthy terms 
and reasonable drilling requirements 
that allow for an orderly and efficient 
development of land holdings. This 
enables us to patiently evaluate our Horn 
River acreage as year-round roads and 
gas-gathering capabilities are expanded. 
We expect to drill seven horizontal Horn 
River wells in 2010 from an estimated 
inventory of about 1,600 drilling locations.

A Solid Base for Growth

Although developing resources such 

as gas shales and the oil sands are growing 
in importance, Devon also produces 
significant quantities of natural gas and 
oil from many established conventional 
producing basins in the United States and 
Canada. Legacy production in these areas 
often holds the leases from which newer 
plays evolve. Much of Devon’s Barnett 
Shale acreage, for example, was held by 
production from conventional oil and gas 
wells drilled decades ago. 

Among Devon’s legacy assets in 

the United States are the Carthage 
and Groesbeck areas of east Texas 
encompassing 350,000 combined net 
acres. These areas include interests in 
several fields that produce primarily 
natural gas from multiple producing 
horizons. Devon curtailed drilling in its 
established east Texas fields in 2009, but 
production remains impressive. Our east 
Texas production averaged more than 
360 million cubic feet of gas equivalent 
per day in 2009.

In west Texas and southeast New 
Mexico, Devon holds nearly 850,000 net 
acres in the Permian Basin. In addition to 
interests in numerous established oil and 
natural gas fields in the Permian, we have 
recently begun pursuing the Wolfberry 
oil play. The Wolfberry features low-risk 
drilling with attractive economics. Devon 
has 142,000 net acres prospective for 

the Wolfberry, holding an estimated 
1,100 undrilled locations. We drilled 45 
Wolfberry wells in 2009 and plan to 
increase activity to 82 wells in 2010. 
In the Rocky Mountains, Devon 
produces natural gas from coal seams in 
the San Juan Basin in New Mexico and 
the Powder River and Wind River Basins 
in Wyoming. In 2008, the company 
acquired interests in another coalbed 
natural gas play in Utah called Drunkard’s 
Wash. Elsewhere in the Rocky Mountains, 
Devon has been among the most active 
drillers in the Washakie area of southern 
Wyoming for many years. We produce 
approximately 120 million cubic feet of 
gas equivalent per day from Washakie, 
where we expect to drill 115 wells in 2010.

13

In Canada, Devon produces natural gas and oil from 

numerous conventional fields in the Western Canadian 
Sedimentary Basin. Among its active areas, Devon holds 
significant acreage positions in both the Peace River Arch of 
west-central Alberta and the Deep Basin, which crosses the 
provincial boundary from west-central Alberta to east-central 
British Columbia. Throughout western Canada, we seek drilling 
objectives at a wide variety of producing zones and depths.
In east-central Alberta and west-central Saskatchewan, 
Devon holds more than 2 million net acres in the Lloydminster 
region. This region produces primarily cold-flow heavy oil that 
is recovered with conventional drilling methods. We drilled 239 
wells at Lloydminster in 2009 and expect to maintain current 
production of about 42,000 barrels equivalent per day in 2010.

11-Year Property Data (1)

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 (3) 
  Oil (per Bbl) 
  Gas (per Mcf) 
  NGLs (per Bbl) 
  Oil, Gas and NGLs (per Boe)  

Unit Production and Operating expense (per Boe) 

$ 
$ 
$ 
$ 

$ 

1999 

2000 

2001 

2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

Growth Rate 

Growth Rate

281  
2,781  
55  
799  
4,616  

23  
295  
5  
77  

17.94  
2.09  
13.28  
14.20  

262  
3,045  
50  
819  
16,332  

34  
417  
7  
110  

25.31  
3.53  
20.87  
22.41  

357  

5,024  

108  

1,302  

6,014  

34  

489  

8  

124  

21.28  

3.84  

16.99  

22.18  

296  

5,836  

192  

1,461  

13,998  

40  

761  

19  

186  

21.59  

2.80  

14.05  

17.54  

360  

7,181  

209  

1,766  

19,275  

45  

856  

22  

209  

26.40  

4.52  

18.63  

26.09  

350  

7,356  

232  

1,808  

19,330  

45  

881  

24  

216  

28.02  

5.34  

23.06  

30.20  

426  

7,170  

246  

1,868  

30,085  

38  

816  

24  

198  

36.62  

7.04  

29.05  

39.57  

499  

8,251  

275  

2,149  

19,353  

32  

807  

23  

190  

56.17  

6.03  

32.10  

39.09  

558  

8,987  

321  

2,376  

29,050  

35  

862  

26  

204  

60.30  

6.01  

37.76  

40.46  

301  

9,879  

352  

2,299  

13,144  

39  

938  

28  

223  

84.05  

7.27  

44.08  

50.71  

686  

9,757  

421  

2,733  

14,873  

42  

966  

30  

233  

51.39  

3.83  

24.71  

28.31  

4.10  

4.78  

5.26  

4.70  

5.77  

6.38  

7.57  

8.46  

9.26  

10.42  

8.51  

  5-Year 

Compound 

10-Year

Compound

14% 

6% 

13% 

9% 

-5% 

-1% 

2% 

5% 

2% 

13% 

-6% 

1% 

-1% 

6% 

9%

13%

23%

13%

12%

6%

13%

20%

12%

11%

6%

6%

7%

8%

For more information on Operations:
www.devonenergy.com/operations
• Detailed maps showing operating areas and statistics
• Devon’s marketing and midstream business

14

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Statistics by Area 

Producing Wells at Year-end 

8,634 

8,330   

6,858    

4,271 

10,390 

38,483 

563 

501 

39,547 

Permian 

mid- 
Continent  

Rocky 
mountains 

Gulf 
Coast 

Canada 

North American 
Onshore 

U.S. 
Offshore 

International 

Total
Company

2009 Production (Net of royalties) 
  Oil (MMBbls) 
  Gas (Bcf) 
  NGLs (MMBbls) 
  Oil, Gas and NGLs (MMBoe)  

Average Prices (1)
  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  
 28  
 3  
 15  

$ 
$ 
$ 
$ 

 56.70  
 3.30  
 23.33  
 38.84  

 96  
 217  
 28  
 161  

 1  
 405  
 17  
 86  

 57.57  
 2.98  
 23.42  
 19.45  

 8  
 5,742  
 275  
 1,239  

 2  
 125  
 1  
 24  

 52.54  
 3.09  
 15.06  
 20.74  

 20  
 918  
 28  
 201  

 2  
 140  
 4  
 29  

 56.82  
 3.62  
 25.97  
 24.29  

 15  
 1,250  
 54  
 277  

 25  
 223  
 4  
 66  

 47.35  
 3.66  
 33.09  
 32.29  

 514  
 1,288  
 34  
 763  

 37  
 921  
 29  
 220  

 50.11  
 3.27  
 24.65  
 25.38  

 653  
 9,415  
 419  
 2,641  

 5  
 45  
 1  
 13  

 60.75  
 4.20  
 27.42  
 38.83  

 33  
 342  
 2  
 92  

 16  
 2  
 -  
 16  

 59.69  
 5.14  
 -    
 59.25  

 107  
 8  
 -  
 108  

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

$ 
$ 

 1,543  

 3,429  

 780  

 1,047  

 7,243  

 14,042  

 831  

 1,815  

 58 
 968
 30
 249 

 53.66
 3.83
 24.71
 30.29

 793 
 9,765 
 421 
 2,841 

 16,688 
 12,914 

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

Gross Wells Drilled During 2009 

Capital Costs Incurred (In millions) (3)
  2009 Actual  
  2010 Forecast 

 297  
 548  

 80  

 860  
 484  

 473  

 580  
 1,812  

 531  
 474  

 2,253  
 5,088  

 4,521  
 8,406  

 139  
 1,029  

 54  
 6,887  

 4,714
 16,322 

 118  

 74  

 385  

 1,130  

 5  

 28  

 1,163

 200  

 1,276  
$ 
$  370 - 425   1,600 - 1,745  

 255  
 290 - 350  

 471  

 3,279  
 1,077  
 580 - 650   1,700 - 1,830   4,540 - 5,000  

 808  
 615 - 725  

 450  

 4,537 
 540 - 630   5,695 - 6,355 

(1)  Total company pricing includes cash settlements related to commodity hedges.
(2)  Estimated future revenue to be generated from the production of proved reserves, net of estimated future production and development costs, discounted at 10%. 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)  2009 actual costs incurred and 2010 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)  $ 

4,616  

16,332  

11-Year Property Data (1)

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 (3) 

  Oil (per Bbl) 

  Gas (per Mcf) 

  NGLs (per Bbl) 

  Oil, Gas and NGLs (per Boe)  

281  

2,781  

55  

799  

23  

295  

5  

77  

17.94  

2.09  

13.28  

14.20  

$ 

$ 

$ 

$ 

$ 

262  

3,045  

50  

819  

34  

417  

7  

110  

25.31  

3.53  

20.87  

22.41  

1999 

2000 

2001 

2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

357  
5,024  
108  
1,302  
6,014  

34  
489  
8  
124  

21.28  
3.84  
16.99  
22.18  

296  
5,836  
192  
1,461  
13,998  

40  
761  
19  
186  

21.59  
2.80  
14.05  
17.54  

360  
7,181  
209  
1,766  
19,275  

45  
856  
22  
209  

26.40  
4.52  
18.63  
26.09  

350  
7,356  
232  
1,808  
19,330  

45  
881  
24  
216  

28.02  
5.34  
23.06  
30.20  

426  
7,170  
246  
1,868  
30,085  

38  
816  
24  
198  

36.62  
7.04  
29.05  
39.57  

499  
8,251  
275  
2,149  
19,353  

32  
807  
23  
190  

56.17  
6.03  
32.10  
39.09  

558  
8,987  
321  
2,376  
29,050  

35  
862  
26  
204  

60.30  
6.01  
37.76  
40.46  

301  
9,879  
352  
2,299  
13,144  

39  
938  
28  
223  

84.05  
7.27  
44.08  
50.71  

686  
9,757  
421  
2,733  
14,873  

42  
966  
30  
233  

51.39  
3.83  
24.71  
28.31  

Unit Production and Operating expense (per Boe) 

4.10  

4.78  

5.26  

4.70  

5.77  

6.38  

7.57  

8.46  

9.26  

10.42  

8.51  

  5-Year 
Compound 
Growth Rate 

10-Year
Compound
Growth Rate

14% 
6% 
13% 
9% 
-5% 

-1% 
2% 
5% 
2% 

13% 
-6% 
1% 
-1% 

6% 

9%
13%
23%
13%
12%

6%
13%
20%
12%

11%
6%
6%
7%

8%

(1)   The years presented exclude 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%. 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)  The average price includes cash settlements related to commodity hedges.

15

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property Highlights

AD

B

C

B

A

B

PeRmIAN

A / Southeast New mexico 

mID-CONTINeNT 

A / Cana-Woodford Shale 

Profile
•  62% average working interest in 573,000 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’.

•  33.6 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled and completed 4 gas wells.
•  Drilled and completed 27 oil wells.
•  Recompleted 22 wells. 
2010 Plans
•  Drill 22 gas wells.
•  Drill 81 oil wells.
•  Recomplete 88 wells.

B / West Texas 

Profile
•  43% average working interest in 1.2 million acres.
•  Key fields include Wasson, Reeves and Anton-Irish  
to the north; Sallie Ann, Ozona, Keystone/Kermit,  

  McKnight and Waddell to the south.
•  Produces oil and gas from multiple formations at  

2,500’ to 18,000’.

•  127.2 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled and completed 48 oil wells, including 45  
  Wolfberry wells.
•  Recompleted 18 wells. 
2010 Plans
•  Drill 137 oil wells, including 82 Wolfberry wells.
•  Recomplete 83 wells.
•  Reactivate 1 well. 

Profile
•  118,000 net acres in the Anadarko Basin in western  
  Oklahoma.
•  Operated working interests range from 27% to 100%.
•  Emerging unconventional natural gas play.
•  Produces gas from the Woodford Shale formation at  

11,500’ to 14,500’.

•  73.1 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled and completed 41 horizontal wells (27  

operated).

•  Drilling focused on acreage evaluation and holding  

leases by establishing production.

•  Acquired additional seismic and acreage.
Installed 70 miles of gas gathering line.
• 
Initiated construction of 200 million cubic feet per  
• 
day gas plant. 

2010 Plans
•  Drill 80 horizontal wells (43 operated).
•  Continue drilling to hold leases by establishing  

production.

•  Begin 500’ offset infill pilots.
•  Acquire additional seismic.
•  Continue construction of gas plant and gathering  

system.

B / Arkoma-Woodford Shale

Profile
•  58,000 net acres in the Arkoma Basin in eastern  
  Oklahoma.
•  Operated working interests range from 22% to 100%.
•  Unconventional natural gas play.
•  Produces gas from the Woodford Shale formation at  

6,000’ to 8,000’.

•  47.2 million barrels of oil equivalent reserves at  

12/31/09. 

16

2009 Activity
•  Drilled and completed 61 horizontal wells (32  

operated).

•  Drilling focused on 1,200’ spaced, long-lateral  

horizontal wells in core area.
Increased 2009 net production 72% over 2008.

• 
•  Acquired additional 3-D seismic.
•  Reprocessed and merged existing 3-D seismic  

data. 
2010 Plans
•  Drill 85 horizontal wells (51 operated).
•  Drilling will focus on 600’ spaced, long-lateral  

horizontal wells in core area.

C / Barnett Shale

Profile
•  663,000 net acres in the Forth Worth Basin of north  

Texas.

•  90% average working interest.
• 
•  Produces gas from the Barnett Shale formation at  

Includes 4,194 producing wells. 

6,500’ to 9,200’.

•  Largest producer in the state’s largest natural gas  
  field.
•  1,026.6 million barrels of oil equivalent reserves at  

12/31/09. 
2009 Activity
•  Drilled and completed 336 horizontal wells (237  

operated).
• 
Increased 2009 net production 4% over 2008.
•  Reduced drilling activity and selectively deferred  

completions for economic considerations.

•  Continued 1,000’ and 500’ offset infill programs.
•  Analyzed select well performance and technical data  

to identify future development opportunities. 

2010 Plans
•  Drill 370 wells (349 operated).
•  Reduce inventory of uncompleted wells.
•  Continue to develop viable areas with 500’ offset  

infill program.

D / Granite Wash 

Profile
•  46,000 net acres in western Oklahoma and the Texas  

panhandle.

•  52% average working interest.
•  Entire acreage position held by production.
• 
•  Produces liquids-rich gas from multiple formations,  
including the prospective Cherokee and Granite  

Includes 533 producing wells. 

  Wash at 10,000’ to 18,000’.
•  25.4 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled and completed 12 wells (3 operated). 
2010 Plans
•  Drill 14 wells (4 operated).

texasOklahOmanew mexicoKansasColoradotexasArkAnsAsOklahOmaGulf of MexicoLouisiana 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
A

B

C

D

e

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’.

•  12.4 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Permitted 50 drill-ready locations.
•  Evaluated seismic to identify future drilling  

locations.

•  Completed gas gathering system improvements.
2010 Plans
•  Drill 38 wells.
•  Recomplete or stimulate 30 wells.
•  Acquire 27 square miles of 3-D seismic.
•  Continue seismic evaluation to identify future  

drilling locations.

B / Powder River Coalbed Natural Gas 

Profile
•  75% average working interest in 353,000 acres in  

northeastern Wyoming.

•  Produces coalbed natural gas from the Fort Union  
  Coal formations at 300’ to 2,000’.
•  20.0 million barrels of oil equivalent reserves at  

Increased 2009 net production 31% over 2008.

12/31/09.
2009 Activity
•  Drilled 15 coalbed natural gas wells.
• 
2010 Plans
•  Drill 24 coalbed natural gas wells.
•  Deepen 9 wells to test Wall coal seam at Spotted  
  Horse.

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’.

•  20.0 million barrels of oil equivalent reserves at  

12/31/09. 
2009 Activity
• 

Initiated first CO2 reinjection at Madison project, 
an enhanced oil recovery project at Beaver Creek.

•  Monitored 5-well coalbed natural gas pilot at  
  Beaver Creek. 
2010 Plans
•  Monitor Madison CO2 enhanced oil recovery 

project.

•  Drill up to 25 coalbed natural gas wells at Beaver  
  Creek and Riverton Dome.
•  Begin gas gathering system installation for coalbed  

natural gas development.

•  Perform select recompletions and workovers.

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’.

•  92.6 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled and completed 95 wells.
• 

Improved drilling efficiencies with new generation  
rigs and multi-well pad drilling.
Installed 51 plunger lifts.
Installed compression and performed other gas  
gathering system improvements.

• 
• 

•  Continued implementation of automated  

production control system.

2010 Plans
•  Drill 115 wells. 
•  Recomplete 15 wells.
• 
•  Complete implementation of automated  

Install 50 plunger lifts.

production control system.

e / Drunkard’s Wash 

Profile
•  44% working interest in 121,000 acres in east- 

central Utah.

•  Produces coalbed natural gas from the Ferron Coal  

formation at 2,800’ to 3,100’.

•  23.3 million barrels of oil equivalent reserves at  

12/31/09. 
2009 Activity
•  Completed 7 wells drilled in 2008.
• 
2010 Plans
•  Drill 2 wells.
• 

Implemented gas gathering system improvements.

Initiate implementation of automated production  
control system.

B

C

A

D

D

D

GULF COAST

A / Groesbeck Area

Profile
•  72% average working interest in 203,000 acres in  

east-central 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 756 producing wells.

• 
•  43.0 million barrels of oil equivalent reserves at  

12/31/09. 
2009 Activity
•  Drilled and completed 10 horizontal wells.
•  Drilled and completed 3 vertical wells.
•  Recompleted 1 well. 
2010 Plans
•  Drill 9 horizontal wells.
•  Drill 8 vertical wells. 
•  Recomplete 31 wells.

B / Carthage Area

Profile
•  86% average working interest in 312,000 acres in  

east Texas.

•  Key fields include Carthage, Bethany, Waskom,  

Stockman and Appleby.

•  Produces primarily gas from the Pettit, Travis Peak,  
  Cotton Valley and Haynesville Lime formations at  

6,400’ to 12,500’.
Includes 1,734 producing wells.

• 
•  184.0 million barrels of oil equivalent reserves at  

12/31/09. 
2009 Activity
•  Drilled and completed 35 wells, including 6 Cotton  
  Valley horizontal wells.
•  Recompleted 5 wells. 
2010 Plans
•  Drill 31 wells, including 10 horizontal wells.
•  Recomplete 16 wells.

C / Haynesville/Bossier Shale 

Profile
•  570,000 net acres in east Texas and northwest  
Louisiana, including 110,000 net acres in the  

  Greater Carthage Area and 47,000 net acres in the  

South Area.

•  92% average working interest.
•  Emerging unconventional natural gas play.
•  Produces gas from the Haynesville and Bossier  

Shale formations at 10,400’ to 14,000’.

•  6.2 million barrels of oil equivalent reserves at  

12/31/09.

17

texasGulf of MexicoLouisianaMSnew mexicoKansasColoradoArizonANebraskaUTAHIDAHOWyomingMontanaSouthDakotaNorthDakota 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2009 Activity
•  Drilled and completed 8 horizontal wells in the  
  Greater Carthage Area.
•  Drilled and completed 1 horizontal well in the  

South Area.

2010 Plans
•  Drill 11 horizontal wells in the Greater Carthage  
  Area (9 net). 
•  Drill 50 horizontal wells in the South Area (14 net).

D / South Texas/South Louisiana 

Profile
•  66% average working interest in 554,000 acres.
•  Key areas include Matagorda, Zapata, Agua  
  Dulce/N. Brayton, Duval/Hagist, Montgomery  
  County Area, Central Texas, Coastal Frio and the  
  Patterson Field in Louisiana.
•  Produces oil and gas from multiple formations at  

1,500’ to 15,000’.

•  31.6 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Completed 4 horizontal Wilcox wells.
•  Drilled 4 vertical Wilcox wells.
•  Drilled 5 additional wells.
•  Recompleted 2 wells. 
2010 Plans
•  Drill 7 horizontal wells.
•  Drill 14 vertical wells.
•  Recomplete 25 wells.

A

B
C

e
D

CANADA

A / Horn River Basin 

Profile
•  100% working interest in 170,000 acres in  

northeastern British Columbia.

•  Emerging unconventional natural gas play.
•  Currently winter-only access.
•  Produces gas from the Devonian Shale formation at  

8,000’ to 10,000’.

•  1.5 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled and completed 3 horizontal wells.
•  Drilled 2 stratigraphic wells.
•  Secured pipeline and processing capacity for future  

production.

•  Acquired additional acreage. 
2010 Plans
•  Drill 7 horizontal wells and complete 4.
•  Drill 4 stratigraphic wells.
•  Expand facilities at Komie. 

B / Northwest 

Profile
•  73% average working interest in 2.6 million acres  
in northwestern Alberta and northeastern British  

  Columbia.
•  Key areas include Hamburg/Chinchaga, Monias,  

Swan Hills, Gift, Tommy/Wargen, Cecil/ 

  Normandville and Valhalla.
•  Full-year and winter-only drilling locations.
•  Produces liquids-rich gas and light gravity oil from  
  multiple formations at 3,000’ to 8,000’.
•  116.8 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled 36 wells, including:
          7 at Wargen
          6 at Swan Hills
          5 at Pouce Coupe 
2010 Plans
•  Drill 55 total wells, including:
        18 at Valhalla
        10 at Dunvegan
        10 at Hamburg
          5 at Wargen
          5 at Normandville       

C / Deep Basin 

Profile
•  45% average working interest in 1.3 million acres in  
  western Alberta and eastern British Columbia.
•  Key areas include Bilbo, Elmorth, Hiding, Pinto,  

Leland/Wild and Wapiti.

•  Produces liquids rich gas from primarily Cretaceous  

and Triassic formations at 6,000’ to 14,000’.
•  59.4 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled 30 wells, including:
          15 at Bilbo
            9 at Pinto
            5 at Wapiti 
2010 Plans
•  Drill 34 total wells, including:
          13 at Bilbo
          12 at Wapiti
            6 at Pinto
            3 at Deep Basin BC

D / Lloydminster 

Profile
•  89% working interest in 2.8 million acres in eastern  
  Alberta and western Saskatchewan.
•  Key areas include End Lake, Iron River,  

Lloydminster and Manatokan.

•  Produces primarily conventional, cold flow heavy  
oil from shallow formations at 1,000’ to 2,000’.
•  81.3 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Drilled 239 wells, including:
         181 at Iron River
           28 at Lloydminster
           14 at Manatokan 
2010 Plans
•  Drill 140 total wells, including:
            97 at Iron River.
            18 at Lloydminster
            18 at Manatokan
              5 at End Lake

e / Thermal Heavy Oil 

Profile
•  56% average working interest in 153,600  

prospective acres in the Jackfish/Kirby area of the  

  Alberta oil sands.
•  Key producing asset is Jackfish (100% interest).
•  Signed agreement to acquire 50% of BP’s interest  

in Kirby oil sands leases.

•  Steam-Assisted Gravity Drainage (SAGD) is the  

• 

• 

recovery method.
Jackfish facilities capacity of 35,000 barrels of oil  
per day.
Jackfish 2 and Jackfish 3 are each 35,000 barrel per  
day look-alike projects.

•  402.8 million barrels of oil equivalent reserves at  

12/31/09.
2009 Activity
•  Production reached approximately 34,000 barrels  

per day at Jackfish.

•  Achieved top-tier reservoir performance at Jackfish.
•  Continued construction of Jackfish 2 facilities.
•  Drilled 14 horizontal well pairs (28 wells) at  

• 

Jackfish 2.
Initiated regulatory approval process for  
Jackfish 3. 

2010 Plans
•  Reach plant capacity of 35,000 barrels per day at  

Jackfish.

•  Continue construction of Jackfish 2 facilities.
•  Drill 14 horizontal well pairs (28 wells) at Jackfish 2.
•  File official regulatory application for Jackfish 3.
•  Drill 24 stratigraphic wells to evaluate additional  

potential in the Jackfish area.

18

SaSkatchewanAlbertABritish ColumBiaNorthwestterritoriesYukonTerriTorYALASKAManitobaNuNavut 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Fracturing and Horizontal Drilling: Game Changing Technology 

A decade ago, U.S. natural gas production was flat, prices 
were steadily rising and plans for new liquefied natural 
gas import terminals were emerging. Meanwhile, drilling 
activity jumped, but national production dropped, and 
experts began to wonder whether the industry had finally 
reached its peak potential in North America.

A shale well is drilled vertically 
thousands of feet through 
several geological layers before 
reaching its target formation 
and turning to a horizontal 
orientation. Once drilling 
is finished, the steel pipe is 
encased in concrete to protect 
groundwater and other rock 
structures. The shale is then 
fractured in multiple stages.

But suddenly, the game began to change. The nation’s 
annual gas production increased by more than a trillion cubic 
feet in 2007 and another trillion plus in 2008. The natural gas 
revolution was on, and shale plays were driving it.

The technological seeds planted in the Barnett Shale by 
George Mitchell in 1981 and enhanced by Devon in 2002 had 
finally germinated. Shale natural gas production had proven 
itself in north Texas and was spreading across North America. 
Hydraulic fracturing, the process of pressuring water 
into wells to crack rock and stimulate production, was the 
technological key. Fracturing paired with horizontal drilling 
opened the Haynesville, Fayetteville, Horn River, Cana-
Woodford, Arkoma-Woodford, Marcellus and other important 
shale formations. Not long ago, these names were obscurities in 
the geological record. Today, they are widely known among the 
natural gas resources that are defining our energy future. 

In 2009, the Colorado-based Potential Gas Committee, 

made up of academics, industry experts and government 
representatives, affirmed shale’s entry in dramatic fashion. The 
committee’s biennial assessment identified an unprecedented 
1,836 trillion cubic feet of natural gas in the United States. That 
is enough gas to meet U.S. demand through the rest of this 
century and beyond. 

While many are celebrating the availability of these 
new abundant sources of clean energy, others question the 
technology. Special interest groups suggest the technology 
could endanger groundwater supplies and say it should be 
regulated under the Environmental Protection Agency’s Clean 
Water Act.  

Meanwhile, two national organizations representing 
state regulatory agencies have spoken out strongly about 
the technology’s safety record. In 2009 the Ground Water 
Protection Council testified to Congress that hydraulic 
fracturing is proven safe under state regulatory supervision. 
Also in 2009, the Interstate Oil and Gas Compact Commission, 
an organization of elected officials and regulators, asserted 
that not a single case of groundwater contamination has been 
documented since the technology was introduced in 1949.

Hydraulic fracturing is safe because of precautions that 

have been in practice for decades. Wells drilled into shale 
formations several thousand feet below surface are sealed from 
adjacent water tables and other geological structures with steel 
pipes encased in concrete. 

Water and sand comprise 99.5% of fracturing solutions 
for natural gas wells. The remaining volume is made up almost 
entirely of products commonly found under household sinks, in 
kitchen refrigerators and in pantries. A list of these chemicals 
can be found in the Corporate Responsibility section of Devon’s 
Web site at: www.devonenergy.com.

Over the past decade, the U.S. energy industry has quietly 
opened a new chapter in its history as a world leader in energy 
innovation and safety. By opening North American natural gas 
shale plays with fracturing and horizontal drilling, the industry 
can provide consumers with reliable supplies of domestic 
natural gas for decades to come.

For more information on Corporate Responsibility: 
www.devonenergy.com/CorpResp/initiatives/Pages/featurestories.aspx
• New drilling technologies have unlocked vast amounts of natural gas 

19

Selected 11-Year Financial Data (1)

1999 

2000 

2001 

 2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

 5-YeAR 

COmPOUND 

GROWTH RATe 

10-YeAR

COmPOUND

GROWTH RATe

OPERATING RESULTS (In millions, except per share data) 
  Revenues (Net of royalties): 

  Oil sales 
  Gas sales   
  NGL sales  
  Net gain (loss) on oil and gas derivative financial instruments 
  Marketing and midstream revenues 
  Other income 

$ 

412  
616  
68  
 —  
20  
12  

843  
1,474  
154  
 —  
53  
35  

732  
1,878  
131  
 —  
71  
51  

  855 
  2,133  
  275  
 —  
  999  
28  

  Total revenues 

1,128 

2,559 

2,863 

  4,290 

7,012 

8,342 

9,816 

9,200 

10,026 

14,075 

8,083 

  Production and operating expenses 
  Marketing and midstream operating 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 and restructuring 
  Interest expense 
  Change in fair value of other financial instruments 
  Reduction of carrying value of oil and gas properties 
  Impairment of Chevron Corporation common stock 
  Income tax (benefit) expense  

317  
10  

374  
 —  
 16  
81  
 17  
108  
 —  
464  
 —  
(74) 

527  
28  

630  
 —  
 41  
91  
 60  
154  
 —  
 —  
 —  
367  

649  
47  

813  
 —  
 34  
113  
 1  
220  
 2  
883  
 —  
(16) 

  874  
  808  

  1,205  
 —  
 —  
  206  
 —  
  530  
 (28) 
  651  
   205  
(206) 

  Total expenses 

1,313  

1,898  

2,746  

  4,245  

5,289  

6,307  

7,076  

6,884  

7,541  

17,114  

10,836  

  Net (loss) earnings before cumulative effect of 

  change in accounting principle and discontinued operations (3) 

  Net (loss) earnings  
  Preferred stock dividends 
  Net (loss) earnings to common stockholders 
  Net (loss) earnings per common share: 

  Basic 
    Diluted 

  Weighted average shares outstanding: 

    Basic 
    Diluted 

BALANCE SHEET DATA (In millions) 
  Total assets 
  Long-term debt 
  Deferred income taxes 
  Stockholders’ equity 
  Common shares outstanding 

(185) 
(154) 
 4  
(158) 

(0.84) 
(0.84) 

187  
187  

6,096  
2,416  
342  
2,521  
253  

$ 

$ 
$ 

$ 
$ 
$ 
$ 

661  
730  
 10  
720  

2.83  
2.75  

255  
263  

117  
103  
 10  
93  

0.37  
0.36  

255  
259  

6,860  
2,049  
606  
3,277  
257  

13,184  
6,589  
2,091  
3,259  
252  

45  
  104  
10  
94  

  0.31  
  0.30  

  309  
  313  

 16,225  
  7,562  
  2,582  
  4,653  
  314  

(1)      All years presented exclude results from discontinued operations. 
(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 the cumulative effect change in accounting principle of $49 and $16 million in 2001 and 2003, respectively, and the results

of discontinued operations of $31, $69, ($63), $59, $8, $151, $114, $530, $1,121, $891 and $274 million in 1999 through 2009, respectively.

N/M   Not a meaningful number.

20

1,179 

3,874  

403  

 —  

1,460  

96  

1,275  

4,698  

548  

 —  

1,701  

120  

1,415  

5,743  

680  

 —  

1,792  

186  

1,821  

4,863  

749  

 38  

1,672  

57  

2,117  

5,138  

970  

 14  

1,736  

51  

3,233  

7,244  

1,243  

 (154) 

2,292  

217  

2,153  

3,197  

747  

 384  

1,534  

68  

1,206  

1,174  

1,377  

1,339  

1,500  

1,335  

1,610  

1,228  

1,890  

1,217  

2,327  

1,611  

1,984  

1,022  

1,594  

1,908  

1,862  

2,127  

2,613  

3,203  

2,108  

 35  

 —  

295  

 7  

496  

 (1) 

 —  

 —  

483  

1,723  

1,747  

 10  

1,737  

4.16  

4.04  

417  

433  

 42  

 —  

277  

 —  

475  

 62  

 —  

 —  

827  

2,035  

2,186  

 10  

2,176  

4.51  

4.38  

482  

499  

 41  

 —  

298  

 —  

533  

 94  

 —  

 —  

1,413  

2,740  

2,930  

 10  

2,920  

6.38  

6.26  

458  

470  

 46  

 —  

404  

 —  

421  

 178  

 —  

 —  

870  

2,316  

2,846  

 10  

2,836  

6.42  

6.34  

442  

448  

 70  

 —  

513  

 —  

430  

 (34) 

 —  

 —  

842  

2,485  

3,606  

 10  

3,596  

8.08  

8.00  

445  

450  

27,162  

8,580  

3,904  

11,056  

472  

30,025  

7,031  

4,658  

13,674  

484  

30,273  

5,957  

4,872  

14,862  

443  

35,063  

5,568  

5,182  

17,442  

444  

41,456  

6,924  

5,991  

22,006  

444  

 80  

 —  

645  

 —  

329  

 149  

9,891  

 —  

(1,121) 

(3,039) 

(2,148) 

 5  

(2,153) 

(4.85) 

(4.85) 

444  

444  

31,908  

5,661  

3,614  

17,060  

444  

 91  

 —  

648  

 105  

349  

 (106) 

6,408  

 —  

(1,773) 

(2,753) 

(2,479) 

 —  

(2,479) 

(5.58) 

(5.58)  

444  

444  

29,686  

5,847  

1,899  

15,570  

447  

11% 

(7%) 

6% 

N/M 

(2%) 

(11%) 

(1%) 

8% 

(5%) 

2% 

17% 

N/M 

19% 

N/M 

(6%) 

N/M 

N/M 

N/M 

N/M 

11% 

N/M 

N/M 

(100%) 

N/M 

N/M 

N/M 

(2%) 

(2%) 

0% 

(4%) 

(16%) 

3% 

(2%) 

18%

18%

27%

N/M

54%

19%

22%

20%

59%

19%

N/M

(100%)

23%

20%

12%

N/M

30%

N/M

(37%)

23%

(31%)

(32%)

(100%)

(32%)

(21%)

(21%)

9%

9%

17%

9%

19%

20%

6%

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1999 

2000 

2001 

 2002 

2003 

2004 

2005 

2006 

2007 

2008 

2009 

 5-YeAR 
COmPOUND 
GROWTH RATe 

10-YeAR
COmPOUND
GROWTH RATe

  Total revenues 

1,128 

2,559 

2,863 

  4,290 

7,012 

8,342 

9,816 

9,200 

10,026 

14,075 

8,083 

1,179 
3,874  
403  
 —  
1,460  
96  

1,275  
4,698  
548  
 —  
1,701  
120  

1,415  
5,743  
680  
 —  
1,792  
186  

1,821  
4,863  
749  
 38  
1,672  
57  

2,117  
5,138  
970  
 14  
1,736  
51  

3,233  
7,244  
1,243  
 (154) 
2,292  
217  

2,153  
3,197  
747  
 384  
1,534  
68  

  Total expenses 

1,313  

1,898  

2,746  

  4,245  

5,289  

6,307  

7,076  

6,884  

7,541  

17,114  

10,836  

1,206  
1,174  

1,594  
 35  
 —  
295  
 7  
496  
 (1) 
 —  
 —  
483  

1,377  
1,339  

1,908  
 42  
 —  
277  
 —  
475  
 62  
 —  
 —  
827  

1,500  
1,335  

1,862  
 41  
 —  
298  
 —  
533  
 94  
 —  
 —  
1,413  

1,610  
1,228  

2,127  
 46  
 —  
404  
 —  
421  
 178  
 —  
 —  
870  

1,890  
1,217  

2,613  
 70  
 —  
513  
 —  
430  
 (34) 
 —  
 —  
842  

2,327  
1,611  

3,203  
 80  
 —  
645  
 —  
329  
 149  
9,891  
 —  
(1,121) 

1,984  
1,022  

2,108  
 91  
 —  
648  
 105  
349  
 (106) 
6,408  
 —  
(1,773) 

1,723  
1,747  
 10  
1,737  

4.16  
4.04  

417  
433  

2,035  
2,186  
 10  
2,176  

4.51  
4.38  

482  
499  

2,740  
2,930  
 10  
2,920  

6.38  
6.26  

458  
470  

2,316  
2,846  
 10  
2,836  

6.42  
6.34  

442  
448  

2,485  
3,606  
 10  
3,596  

8.08  
8.00  

445  
450  

27,162  
8,580  
3,904  
11,056  
472  

30,025  
7,031  
4,658  
13,674  
484  

30,273  
5,957  
4,872  
14,862  
443  

35,063  
5,568  
5,182  
17,442  
444  

41,456  
6,924  
5,991  
22,006  
444  

(3,039) 
(2,148) 
 5  
(2,153) 

(4.85) 
(4.85) 

444  
444  

31,908  
5,661  
3,614  
17,060  
444  

(2,753) 
(2,479) 
 —  
(2,479) 

(5.58) 
(5.58)  

444  
444  

29,686  
5,847  
1,899  
15,570  
447  

OPERATING RESULTS (In millions, except per share data) 

  Revenues (Net of royalties): 

  Oil sales 

  Gas sales   

  NGL sales  

  Net gain (loss) on oil and gas derivative financial instruments 

  Marketing and midstream revenues 

  Other income 

  Production and operating expenses 

  Marketing and midstream operating 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 and restructuring 

  Interest expense 

  Change in fair value of other financial instruments 

  Reduction of carrying value of oil and gas properties 

  Impairment of Chevron Corporation common stock 

  Income tax (benefit) expense  

  Net (loss) earnings before cumulative effect of 

  change in accounting principle and discontinued operations (3) 

  Net (loss) earnings  

  Preferred stock dividends 

  Net (loss) earnings to common stockholders 

  Net (loss) earnings per common share: 

  Weighted average shares outstanding: 

  Basic 

    Diluted 

    Basic 

    Diluted 

BALANCE SHEET DATA (In millions) 

  Total assets 

  Long-term debt 

  Deferred income taxes 

  Stockholders’ equity 

  Common shares outstanding 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

$ 

412  

616  

68  

 —  

20  

12  

317  

10  

374  

 —  

 16  

81  

 17  

108  

 —  

464  

 —  

(74) 

(185) 

(154) 

 4  

(158) 

(0.84) 

(0.84) 

187  

187  

6,096  

2,416  

342  

2,521  

253  

843  

1,474  

154  

 —  

53  

35  

732  

1,878  

131  

 —  

71  

51  

527  

28  

630  

 —  

 41  

91  

 60  

154  

 —  

 —  

 —  

367  

661  

730  

 10  

720  

2.83  

2.75  

255  

263  

649  

47  

813  

 —  

 34  

113  

 1  

220  

 2  

883  

 —  

(16) 

117  

103  

 10  

93  

0.37  

0.36  

255  

259  

6,860  

2,049  

606  

3,277  

257  

13,184  

6,589  

2,091  

3,259  

252  

  855 

  2,133  

  275  

  999  

 —  

28  

  874  

  808  

  1,205  

 —  

 —  

 —  

  206  

  530  

 (28) 

  651  

   205  

(206) 

  104  

45  

10  

94  

  0.31  

  0.30  

  309  

  313  

 16,225  

  7,562  

  2,582  

  4,653  

  314  

(1)      All years presented exclude results from discontinued operations. 

(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 the cumulative effect change in accounting principle of $49 and $16 million in 2001 and 2003, respectively, and the results

of discontinued operations of $31, $69, ($63), $59, $8, $151, $114, $530, $1,121, $891 and $274 million in 1999 through 2009, respectively.

N/M   Not a meaningful number.

11% 
(7%) 
6% 
N/M 
(2%) 
(11%) 

(1%) 

8% 
(5%) 

2% 
17% 
N/M 
19% 
N/M 
(6%) 
N/M 
N/M 
N/M 
N/M 

11% 

N/M 
N/M 
(100%) 
N/M 

N/M 
N/M 

(2%) 
(2%) 

0% 
(4%) 
(16%) 
3% 
(2%) 

18%
18%
27%
N/M
54%
19%

22%

20%
59%

19%
N/M
(100%)
23%
20%
12%
N/M
30%
N/M
(37%)

23%

(31%)
(32%)
(100%)
(32%)

(21%)
(21%)

9%
9%

17%
9%
19%
20%
6%

21

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheets

DEVON ENERGy CORPORATION AND SUBSIDIARIES

ASSETS
Current assets:
  Cash and cash equivalents  
  Accounts receivable  
  Derivative financial instruments, at fair value  
  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 ($4,078 million and $4,248 million excluded from
  amortization in 2009 and 2008, respectively)  
Less accumulated depreciation, depletion and amortization  
  Property and equipment, net  
Goodwill  
Long-term assets held for sale  
Other long-term assets, including $246 million and $199 million at fair value in
  2009 and 2008, respectively  

  Total assets  

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
  Accounts payable - trade  
  Revenues and royalties due to others  
  Short-term debt  
  Current portion of asset retirement obligations, at fair value  
  Current liabilities associated with assets held for sale  
  Other current liabilities, including $38 million at fair value in 2009  

  Total current liabilities  

Long-term debt  
Asset retirement obligations, at fair value  
Liabilities associated with assets held for sale, including $109 million and $98
  million at fair value in 2009 and 2008, respectively  
Other long-term liabilities  
Deferred income taxes  
Stockholders’ equity:
  Common stock of $0.10 par value.  Authorized 1.0 billion shares; 
      issued 446.7 million and 443.7 million shares in 2009 and 2008, respectively  
    Additional paid-in capital  
    Retained earnings  
    Accumulated other comprehensive income  

  Total stockholders’ equity  
Total liabilities and stockholders’ equity  

December 31,  

 2009  
2008 
(In millions, except share data)

 $ 

 $ 

 $ 

646  
 1,208  
 211  
 657  
 270  
 2,992  

 60,475  
 41,708  
 18,767  
 5,930  
 1,250  

 747  
29,686  

1,137  
 486  
 1,432  
 95  
 234  
 418  
 3,802  
 5,847  
 1,418  

 213  
 937  
 1,899  

 45  
 6,527  
 7,613  
 1,385  
 15,570  
29,686  

 $ 

195 
1,300 
 282 
 392 
 515 
2,684 

53,391 
31,360 
22,031 
 5,511 
1,128 

 554 
31,908 

1,612 
490 
180 
138 
 365 
 350 
3,135 
5,661 
1,249 

166 
1,023 
3,614 

 44 
6,257 
10,376 
383 
17,060 
31,908 

For notes to consolidated financial statements see Form 10-K:
investor.dvn.com

22

 
 
 
 
  
 
  
 
  
 
 
 
 
 
 
 
 
 
  
 
  
 
  
 
  
 
 
 
  
 
 
 
 
 
  
 
  
 
  
 
  
 
 
 
 
 
 
 
  
 
  
 
  
 
  
 
  
 
  
 
 
 
  
 
  
 
  
      
 
  
  
Consolidated Statements of Operations

DEVON ENERGy CORPORATION AND SUBSIDIARIES

Revenues: 
  Oil, gas and NGL sales  
  Net gain (loss) on oil and gas derivative financial instruments  
  Marketing and midstream revenues  

  Total revenues  

Expenses and other income, net: 
  Lease operating expenses  
  Taxes other than income 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 obligations  
    General and administrative expenses  
    Restructuring costs  
    Interest expense  
    Change in fair value of other financial instruments  
    Reduction of carrying value of oil and gas properties  
    Other income, net  

  Total expenses and other income, net  

Earnings (loss) from continuing operations before income taxes  
Income tax expense (benefit): 
  Current  
  Deferred  
       Total income tax expense (benefit)  
Earnings (loss) from continuing operations  
Discontinued operations: 
  Earnings from discontinued operations before income taxes  
  Discontinued operations income tax expense   
  Earnings from discontinued operations  

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

Basic net earnings (loss) per share: 
  Basic earnings (loss) from continuing operations per share  
  Basic earnings from discontinued operations per share  
  Basic net earnings (loss) per share  

Diluted net earnings (loss) per share: 
  Diluted earnings (loss) from continuing operations per share  
  Diluted earnings from discontinued operations per share  
  Diluted net earnings (loss) per share  

 Year ended December 31, 

 2009  

 2008  
(In millions, except per share amounts) 

 2007 

 $ 

 $ 

 $ 

 $ 

 $ 

 $ 

6,097  
 384  
 1,534  
 8,015  

1,670  
 314  
 1,022  
 1,832  
 276  
 91  
 648  
 105  
 349  
 (106) 
 6,408  
 (68) 
 12,541  
 (4,526) 

 241  
 (2,014) 
 (1,773) 
 (2,753) 

 322  
 48  
 274  
 (2,479) 
 —  
(2,479) 

 11,720  
 (154) 
 2,292  
 13,858  

 1,851  
 476  
 1,611  
 2,948  
 255  
 80  
 645  
 —  
 329  
 149  
 9,891  
 (217) 
 18,018  
 (4,160) 

 441  
 (1,562) 
 (1,121) 
 (3,039) 

 1,258  
 367  
 891  
 (2,148) 
 5  
 (2,153) 

(6.20) 
 0.62  
(5.58) 

 (6.86) 
 2.01  
 (4.85) 

(6.20) 
 0.62  
(5.58) 

 (6.86) 
 2.01  
 (4.85) 

 8,225 
 14 
 1,736 
 9,975 

 1,532 
 358 
 1,217 
 2,412 
 201 
 70 
 513 
 — 
 430 
 (34)
 — 
 (51)
 6,648 
 3,327 

 235 
 607 
 842 
 2,485 

 1,593 
 472 
 1,121 
 3,606 
 10 
 3,596 

 5.56 
 2.52 
 8.08 

 5.50 
 2.50 
 8.00 

23

 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Consolidated Statements of Comprehensive (Loss) Income

DEVON ENERGy CORPORATION AND SUBSIDIARIES

 Year ended December 31,  

2009  

 2008  
(In millions) 

 2007 

Net earnings (loss)  

 $ 

(2,479) 

 (2,148) 

 3,606 

Foreign currency translation: 
  Change in cumulative translation adjustment  
  Foreign currency translation income tax benefit (expense)  
  Foreign currency translation total  

Pension and postretirement benefit plans: 
  Net actuarial gain (loss) and prior service cost arising in current year  
    Recognition of net actuarial loss and prior service cost in net earnings (loss)  
    Curtailment of pension benefits  
    Pension and postretirement benefit plans income tax benefit (expense)  
    Pension and postretirement benefit plans total  
Reclassification adjustment for realized gains included in net earnings  
Other comprehensive earnings (loss), net of tax  
Comprehensive income (loss)  

993  
(62) 
931  

 (1,960) 
 79  
 (1,881) 

 1,389 
 (42)
 1,347 

59  
54  
—  
 (42) 
 71  
 —  
 1,002  
(1,477) 

 (239) 
 18  
—  
 80  
 (141) 
 —  
 (2,022) 
(4,170) 

 (90)
 14 
 16 
 23 
 (37)
 (1)
 1,309 
4,915 

 $ 

For notes to consolidated financial statements see Form 10-K:
investor.dvn.com

24

 
 
  
 
 
 
 
 
 
 
 
  
  
  
 
 
  
  
 
 
 
 
 
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 

 $ 

Balance as of December 31, 2006  
Net earnings (loss)  
Other comprehensive earnings (loss), net of tax  
Other financial instruments  
Uncertain income tax positions  
Pension and postretirement benefit plans  
Stock option exercises  
Restricted stock grants, net of cancellations  
Common stock repurchased  
Common stock retired  
Common stock dividends  
Preferred stock dividends  
Share-based compensation  
Share-based compensation tax benefits  

Balance as of December 31, 2007  
Net earnings (loss)  
Other comprehensive earnings (loss), net of tax  
Stock option exercises  
Restricted stock grants, net of cancellations  
Common stock repurchased  
Common stock retired  
Redemption of preferred stock  
Common stock dividends  
Preferred stock dividends  
Share-based compensation  
Share-based compensation tax benefits  

1  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  

 1  
 —  
 —  
 —  
 —  
 —  
 —  
 (1) 
 —  
 —  
 —  
 —  

Balance as of December 31, 2008  
Net earnings (loss)  
Other comprehensive earnings (loss), net of tax  
Stock option exercises  
Restricted stock grants, net of cancellations  
Common stock repurchased  
Common stock retired  
Common stock dividends  
Share-based compensation  
Share-based compensation tax benefits  
Balance as of December 31, 2009  

  — 
  — 
  — 
  — 
  — 
  — 
  — 
  — 
  — 
  — 
$  — 

   444  
 —  
 —  
 —  
 —  
 —  
 3  
 2  
(5) 
 —  
 —  
   —  
   —  
   —  

   444  
 —  
 —  
4  
3  
(7) 
   —  
   —  
   —  
 —  
   —  
   —  

  444  
 —  
 —  
 1  
 2  
 —  
 —  
 —  
 —  
 —  
   447  

 $  44  
   —  
   —  
   —  
 —  
 —  
1  
 —  
 —  
(1)  
 —  
 —  
 —  
   —  

   44  
 —  
 —  
1  
 —  
 —  
(1) 
 —  
   —  
 —  
 —  
 —  

   44  
 —  
 —  
1  
   —  
 —  
 —  
 —  
 —  
 —  
 $  45  

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

 6,743  
 —  
 —  
 123  
 —  
 —  
 (716) 
 (149) 
 —  
 —  
 196  
 60  

 6,257  
 —  
 —  
 47  
 —  
 —  
 (45) 
 —  
 260  
 8  
 6,527   

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

 12,813  
 (2,148) 
 —  
 —  
 —  
 —  
 —  
 —  
 (284) 
 (5) 
 —  
 —  

 10,376  
 (2,479) 
 —  
 —  
 —  
 —  
 —  
 (284) 
 —  
 —  
7,613   

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

 2,405  
 —  
 (2,022) 
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 —  

 383  
 —  
 1,002  
 —  
 —  
 —  
 —  
 —  
 —  
 —  
1,385   

 (1) 
 —  
 —  
 —  
 —  
 —  
 —  
 —  
 (362) 
 363  
 —  
 —  
 —  
 —  

 —  
 —  
 —  
 (8) 
 —  
 (709) 
 717  
 —  
 —  
 —  
 —  
 —  

 —  
 —  
 —  
 (5) 
 —  
 (40) 
 45  
 —  
 —  
 —  
—  

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

 22,006 
 (2,148)
 (2,022)
 116 
 — 
 (709)
 — 
 (150)  
 (284)
 (5)
 196 
 60 

 17,060 
 (2,479)
 1,002 
 43 
 — 
 (40)
 — 
 (284)
 260 
 8 
 15,570 

25

 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
  
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
  
 
  
 
 
  
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
Consolidated Statements of Cash Flows

DEVON ENERGy CORPORATION AND SUBSIDIARIES

Cash flows from operating activities: 
  Net earnings (loss)  
  Net earnings from discontinued operations  
  Adjustments to reconcile earnings (loss) from continuing operations 

  to net cash provided by operating activities: 
  Depreciation, depletion and amortization  
  Deferred income tax expense (benefit)  

       Reduction of carrying value of oil and gas properties  
       Net unrealized loss (gain) on oil and gas derivative financial instruments  
       Other noncash charges  
       Net decrease (increase) in working capital  
       Decrease (increase) in long-term other assets  

Increase (decrease) in 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  
    Proceeds from exchange of Chevron Corporation common stock  
    Purchases of short-term investments  
    Sales of long-term and short-term investments  
    Other    
    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: 
  Proceeds from borrowings of long-term debt, net of issuance costs  
    Credit facility repayments  
    Credit facility borrowings  
    Net commercial paper borrowings (repayments)  
    Debt repayments  
    Redemption of preferred stock  
    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 provided by (used in) financing activities  
Effect of exchange rate changes on cash  
Net increase (decrease) in cash and cash equivalents  
Cash and cash equivalents at beginning of period (including cash  
  related to assets held for sale)  
Cash and cash equivalents at end of period (including cash related  
  to assets held for sale)  

For notes to consolidated financial statements see Form 10-K:
investor.dvn.com

26

 Year ended December 31, 

 2009  

 2008  
 (In millions)  

 2007 

 $ 

(2,479) 
 (274) 

(2,148) 
 (891) 

3,606 
 (1,121)

 2,108  
 (2,014) 
 6,408  
 121  
 222  
 149  
 (6) 
 (3) 
 4,232  
 505  
 4,737  

 34  
 (4,879) 
 —  
 —  
 7  
(17) 
 (4,855) 
 (499) 
 (5,354) 

 1,187  
 —  
 —  
 426  
 (178) 
 —  
 42  
 —  
 (284) 
 8  
 1,201  
 43  
 627  

 3,203  
 (1,562) 
 9,891  
 (243) 
 410  
 (207) 
 (53) 
 48  
 8,448  
 960  
 9,408  

 117  
 (8,843) 
 280  
 (50) 
 300  
 —  
 (8,196) 
 1,323  
 (6,873) 

 —  
 (3,191) 
 1,741  
 1  
 (1,031) 
 (150) 
 116  
 (665) 
 (289) 
 60  
 (3,408) 
 (116) 
 (989) 

 2,613 
 607 
 — 
 26 
 150 
 (512)
 (60)
 (1)
 5,308 
 1,343 
 6,651 

 76 
 (5,710)
 — 
 (934)
 1,136 
 — 
 (5,432)
 (282)
 (5,714)

 — 
 (757)
 2,207 
 (804)
 (567)
 — 
 91 
 (326)
 (259)
 44 
 (371)
 51 
 617 

 384  

 1,373  

 756 

 $ 

1,011  

 384  

 1,373 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
      
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Directors

J. Larry Nichols, 67, is a co-founder of 
Devon and serves as chairman of the board 
of directors and chief executive officer. 
Nichols also serves as chairman of the 
Dividend Committee. Nichols was 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. and is chairman of the 
American Petroleum Institute. Nichols holds a Bachelor of Arts 
degree in geology from Princeton University and a law degree from 
the University of Michigan.

Thomas F. Ferguson, 73, 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.

John A. Hill, 68, joined the board of 
directors in 2000 following Devon’s merger 
with Santa Fe Snyder Corp. and serves as 
chairman of the Governance Committee. 
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 administrator of 
the Federal Energy Administration during the Ford Administration. 
Hill is chairman of the board of trustees of the Putnam Funds in 
Boston, a trustee of Sarah Lawrence College and director of various 
companies controlled by First Reserve Corp.

Robert L. Howard, 73, joined the board 
of directors in 2003 and is chairman of 
the Compensation 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.

michael m. kanovsky, 61, joined the board 
of directors in 1998. He was a co-founder of 
Northstar Energy Corporation and served 
on Northstar’s board of directors from 
1982 to 1998. Kanovsky currently serves as 
president of Sky Energy Corp. He also serves 
as a director of Argosy Energy Inc., ARC 
Resources Ltd., Bonavista Petroleum Ltd., 
Pure Technologies Ltd. and TransAlta Corp.

J. Todd mitchell, 51, joined the board of 
directors in 2002. He currently serves as 
president of Two Seven Ventures, LLC, 
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.

Robert A. mosbacher, 58, joined the board 
of directors in 2009. He previously served 
as a member of the board from 1999 until 
2005, at which time he resigned to accept 
an appointment by the Bush administration 
to serve as president and chief executive 
officer of the Overseas Private Investment 
Corporation, where he served until January 
2009. He previously served as president 

and chief executive officer of Mosbacher Energy Company, an 
independent oil and gas exploration and production company, 
from 1986 to 2005.  Mr. Mosbacher currently serves as a director of 
Calpine Corporation.

mary P. Ricciardello, 54, 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 vice 
president and chief accounting officer. She serves on the boards of 
U.S. Concrete and Noble Corp. and is a Certified Public Accountant.

John Richels, 59, is a member of the board 
of directors and serves as president of 
Devon. He has been with the company since 
the 1998 acquisition of the Canadian-based 
Northstar Energy Corporation. Prior to 
joining Northstar, Richels 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.

27

Senior Officers

Jeff A. Agosta, 42, executive vice 
president and chief financial officer, has 
been with the company since 1997. He 
most recently held the position of senior 
vice president, corporate finance and 
treasurer. Prior to joining Devon, Agosta 
was with the management consulting 
firm of D. R. Payne and Associates and 
KPMG Peat Marwick (now KPMG LLP). 

He holds a bachelor’s degree in accounting from the University of 
Oklahoma and is a Certified Public Accountant.

David A. Hager, 53, executive vice 
president, Exploration and Production, 
has been with the company since March 
2009. He was previously a member of 
Devon’s board of directors. Hager served 
as chief operating officer of Kerr-McGee 
Corp. prior to its merger with Anadarko 
Petroleum Corp. in 2006. He holds a 
Bachelor of Science degree in geophysics 

from Purdue University and a master’s degree in business 
administration from Southern Methodist University.

R. Alan marcum, 43, executive vice 
president, Administration, has been 
with the company since 1995. Marcum 
most recently held the position of vice 
president and controller. Prior to joining 
Devon, Marcum was employed by KPMG 
Peat Marwick (now KPMG LLP) as a senior 
auditor. He holds a Bachelor of Science 
degree in accounting and finance from 

East Central University. Marcum is a Certified Public Accountant 
and a member of the Oklahoma Society of Certified Public 
Accountants.

Frank W. Rudolph, 53, executive vice 
president, Human Resources, has been 
with the company since 2007. Prior to 
joining Devon, Rudolph was vice president 
Human Resources for Banta Corp. (now 
R.R. Donnelley), an international printing 
and supply chain management company. 
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.

Darryl G. Smette, 62, executive vice 
president, Marketing and Midstream, has 
been with the company since 1986. 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, 51, executive vice 
president and general counsel, has been 
with the company since 2005. Prior to 
joining Devon, Taylor was with Skadden, 
Arps, Slate, Meagher & Flom, LLP for 20 
years, most recently as managing partner 
of the firm’s Houston 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.

William F. Whitsitt, 65, executive 
vice president, Public Affairs, has been 
with the company since 2008. Prior to 
joining Devon, Whitsitt spent 11 years 
in Washington D.C. as a public affairs 
consultant. He held the positions of 
president and chief operating officer 
for the American Exploration and 
Production Council (previously the 

Domestic Petroleum Council). Whitsitt also previously served as 
director of Governmental Affairs for the law firm Skadden, Arps, 
Slate, Meagher & Flom, LLP and vice president of Worldwide 
Marketing and Public Affairs for Oryx Energy. Whitsitt holds a 
doctoral degree in public administration from George Washington 
University.

28

For more information on Management:
www.devonenergy.com/AboutDevon/Pages/management_team
• Directors, Senior Officers as well as other executives

Corporate Headquarters
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260
Telephone: (405) 235-3611
Fax: (405) 552-4667

Permian, Mid-Continent,
Rocky Mountains and
Marketing and Midstream Operations
Devon Energy Corporation
20 North Broadway
Oklahoma City, OK 73102-8260
Telephone: (405) 235-3611

Gulf Coast Operations
Devon Energy Corporation
Devon Energy Tower
1200 Smith Street
Houston, TX 77002-4313
Telephone: (713) 286-5700

Canadian Operations
Devon Canada Corporation
2000, 400 - 3rd Avenue S.W.
Calgary, Alberta T2P 4H2
Telephone: (403) 232-7100

Royalty Owner Assistance
Telephone: (405) 228-4800
E-mail: DevonRevenueHotline@dvn.com 

Shareholder Assistance
For information about transfer or 
exchange of shares, dividends, address 
changes, account consolidation, multiple 
mailings, lost certificates and Form 1099, 
contact:

Computershare Trust Company, N.A.
PO Box 43078
Providence, RI 02940-3078
Toll free: (877) 860-5820
E-mail: web.queries@computershare.com

Investor Relations Contacts
Vince White, Senior Vice President
Investor Relations
Telephone: (405) 552-4505
E-mail: vince.white@dvn.com

Shea Snyder, Senior Manager, Investor 
Relations
Telephone: (405) 552-4782
E-mail: shea.snyder@dvn.com

Scott Coody, Manager, Investor Relations
Telephone: (405) 552-4735
E-mail: scott.coody@dvn.com

Media Contact
Chip Minty, Manager, Media Relations
Telephone: (405) 228-8647
E-mail: chip.minty@dvn.com

Annual Meeting
Our annual shareholders’ meeting will be held at 
8 a.m. Central Time on Wednesday, June 9, 2010, 
at the Skirvin Hotel, Continental Room,  
1 Park Avenue, 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 14,000 
shareholders of record.

Online Publications
A copy of Devon’s Summary Annual Report,  
SEC Form 10-K and Corporate Responsibility 
Report are available at: www.devonenergy.com.

A print version of these publications are 
available upon request to: 
Judy Roberts, Shareholder Services 
Administrator 
Telephone: (405) 552-4570
Email: judy.roberts@dvn.com

Discover the difference

Devon Energy  2008-2009 Corporate Responsibility Report

Corporate 
Responsibility 
Report

Form 10-K

This report was printed on certified recycled paper.

29

Common Stock Trading DataInvestor Information2008Quarter HigH Low Last totaL VoLumeFirst    108.13   74.56   104.33   280,696,802 Second   127.16   101.31   120.16   272,445,836 Third    127.43   82.10   91.20   465,638,876 Fourth   91.69   54.40   65.71   437,273,430 2009Quarter HigH Low Last totaL VoLumeFirst    73.11   38.55   44.69   444,935,900 Second   67.40   43.35   54.50   357,336,600 Third    72.91   48.74   67.33   289,142,600 Fourth   75.05   62.60   73.50   264,495,500 Forward-Looking Statements  This Summary Annual Report includes “forward-looking statements” as defined by securities laws. These statements refer to our objectives, estimates, expectations, and strategic plans for our future operations. Other than statements of historical facts, all statements included in this Report that address activities, events, or developments that Devon expects, believes, or anticipates may or will occur in the future are forward-looking statements. Such statements are subject to a number of assumptions, risks, and uncertainties, many of which are beyond the control of Devon. We discuss our principal assumptions, risks, and uncertainties in our most recent Form 10-K. We encourage our investors to review and consider those matters as they may cause Devon’s actual results to differ materially from our expectations. The forward-looking statements in this Report are made as of the date of this Report, even if this Report is subsequently made available by us on our website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events, or otherwise.    www.devonenergy.com