Devon Energy
Annual Report 2009

Plain-text annual report

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 2 5 6 8 10 14 15 16 19 20 22 27 28 29 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 

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