- Key areas include Grizzly, Narraway, Lynx, Findley, Cabin Creek and Coleman
- High-impact, long-lived reserves
- Produces gas from multiple formations at 4,000’ to 15,000’
- Actual capital expenditures: $68 million
- Drilled 5 wells, including: 3 at Grizzly, 1 at Coleman, 1 at Findley
- Planned capital expenditures: ≈$30 million
- Operated rigs running: 0
- Drill 2 total wells at Grizzly
- 174,000 net acres in northeastern British Columbia
- 94% average working interest
- 9 producing wells
- Production (Q3 net): 2 MBOED (0% liquids)
- Reserves (12/31/10): 11 MMBOE (0% liquids)
- Emerging shale gas play
- Primarily winter-only access
- Produces gas from the Devonian Shale formation at 8,000’ to 10,000’
- Actual capital expenditures: $165 million
- Drilled 7 horizontal wells
- Completed and brought online 4 horizontal wells
- Planned capital expenditures: ≈$100 million
- Operated rigs running: 0
- Drill 3 stratigraphic wells
- Complete and test 2 vertical exploratory wells
- Continue construction of Cabin Creek gas plant
- 1,832,000 net acres in northwestern Alberta and northeastern British Columbia
- 74% average working interest
- 3,677 producing wells
- Production (Q3 net): 40 MBOED (24% liquids)
- Reserves (12/31/10): 107 MMBOE (38% liquids)
- Key areas include Dunvegan, Hamburg/Chinchaga, Monias, Swan Hills, 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’
- Actual capital expenditures: $249 million
- Drilled 67 wells, including: 12 at Dunvegan, 8 at Monias, 8 at Pouce Coupe, 8 at Valhalla, 7 at Wargen, 7 at Knopcik, 7 at Hamburg
- Planned capital expenditures: ≈$160 million
- Operated rigs running: 2
- Drill 49 total wells, including: 28 at Valhalla, 6 at Dunvegan, 3 at Mitsue
- 2,660,000 net acres in eastern Alberta and southern Saskatchewan
- 87% average working interest
- 3,814 producing wells
- Production (Q3 net): 40 MBOED (82% liquids)
- Reserves (12/31/10): 65 MMBOE (80% liquids)
- 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’
- Actual capital expenditures: $110 million
- Drilled 191 wells, including: 121 at Iron River, 33 at Lloydminster, 20 at Manatokan
- Planned capital expenditures: ≈$180 million
- Operated rigs running: 1
- Drill ≈190 total wells, including: 90 at Iron River, 35 at Lloydminster, 30 at Manatokan
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- 127,000 net acres
- 28 producing wells
- Production (Q3 net): 38 MBOED (100% liquids) 6% of Total Company
- Reserves (12/31/10): 440 MMBOE (100% liquids) 15% of Total Company
- 58,850 net acres in eastern Alberta’s oil sands
- 50% average working interest
- 0 producing wells
- Production (Q3 net): NA
- Reserves (12/31/10): NA
- Devon-operated joint-venture with BP
- Located immediately adjacent to Jackfish acreage
- In early stages of development
- Steam-Assisted Gravity Drainage (SAGD) will be the recovery method
- Actual capital expenditures: $20 million
- Acquired position
- Drilled 44 stratigraphic wells
- Planned capital expenditures: ≈$160 million
- Operated rigs running: 0
- Drill 107 stratigraphic wells to further delineate the Pike resource
- Acquire approximately 60 square miles of 3-D seismic
- 36,500 net acres in eastern Alberta’s oil sands
- 100% average working interest
- 28 producing wells
- Production (Q3 net): 36 MBOED (100% liquids)
- Reserves (12/31/10): 441 MMBOE (100% liquids)
- Steam-Assisted Gravity Drainage (SAGD) is the recovery method
- Projects include Jackfish, Jackfish 2 and Jackfish 3, each with facilities capacity of 35,000 barrels of oil per day
- Jackfish 2 to begin production in 2011
- Jackfish 3 currently in the regulatory approvals process
- Actual capital expenditures: $511 million
- Drilled 37 stratigraphic wells to evaluate additional potential in the Jackfish area
JACKFISH
- Jackfish continued to perform in the top-tier of SAGD projects
- Production reached approximately 34,000 barrels per day
- Drilled 7 horizontal well pairs (14 wells)
JACKFISH 2
- Facilities deemed mechanically complete
- Drilled 19 horizontal wells pairs (38 wells)
JACKFISH 3
- Filed official regulatory application
- Initiated detailed engineering and procurement work
- Planned capital expenditures: ≈$520 million
- Operated rigs running: 0
- Drill ≈60 stratigraphic wells to evaluate additional potential in the Jackfish area
JACKFISH
- Drill 14 horizontal well pairs (28 wells)
JACKFISH 2
- Drill 7 horizontal well pairs (14 wells)
- Commence steam injection
JACKFISH 3
- Obtain regulatory approval
- 733,000 net acres in western Alberta and eastern British Columbia
- 45% average working interest
- 1,283 producing wells
- Production (Q3 net): 41 MBOED (14% liquids)
- Reserves (12/31/10): 56 MMBOE (18% liquids)
- Key areas include Bilbo, Elmworth, Hiding, Pinto, Leland/Wild and Wapiti
- Produces gas from primarily Cretaceous and Triassic formations at 6,000’ to 14,000’
- Actual capital expenditures: $141 million
- Drilled 39 wells, including: 24 at Bilbo, 7 at Wapiti, 4 at Pinto
- Planned capital expenditures: ≈$180 million
- Operated rigs running: 0
- Drill 40 total wells
- 998,000 net acres in southern Alberta and Saskatchewan
- 77% average working interest
- 1,431 producing wells
- Production (Q3 net): 18 MBOED (25% liquids)
- Reserves (12/31/10): 40 MMBOE (39% liquids)
- Key areas include Brazeau, Ferrier, Halkirk and Wimborne
- Produces oil and gas from multiple formations at 4,000’ to 12,000’
- Actual capital expenditures: $125 million
- Drilled 35 wells, including: 14 at Ferrier, 7 at Edson, 4 at Kaybob
- Planned capital expenditures: ≈$160 million
- Operated rigs running: 0
- Drill 21 total wells, including: 10 at Ferrier, 1 at Peco
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- 2,200,000 net acres
- 6,112 producing wells
- Production (Q3 net): 65 MBOED (26% liquids),
10% of Total Company
- Reserves (12/31/10): 212 MMBOE (26% liquids),
7% of Total Company
- 465,500 net acres in north-central Montana
- 90% average working interest
- 883 producing wells
- Production (Q3 net): 4 MBOED (0% liquids)
- Reserves (12/31/10): 14 MMBOE (0% liquids)
- Produces gas from the Eagle formation at 800’ to 2,000’
- Actual capital expenditures: $10 million
- Drilled 31 wells
- Acquired 25 square miles of 3-D seismic
- Planned capital expenditures: $1 million
- Operated rigs running: 0
- Continue seismic evaluation to identify future drilling locations
- 220,000 in the Powder River Basin of northeastern Wyoming
- 75% average working interest
- 952 producing wells
- Production (Q3 net): 17 MBOED (9% liquids)
- Reserves (12/31/10): 21 MMBOE (11% liquids)
- Produces coalbed natural gas from the Fort Union Coal formation at 700’ to 2,500’
- Produces oil from multiple formations at 8,000’ to 11,000’
- Approximately 137,000 net acres are prospective for oil in Niobrara and Parkman formations
- Actual capital expenditures: $37 million
- Drilled 29 coalbed natural gas wells
- Acquired acreage prospective in the Niobrara, Parkman and other formations
- Acquired 3-D seismic
- Planned capital expenditures: ≈$65 million
- Operated rigs running: 3
- Drill 8 horizontal oil wells
- Drill 4-5 exploratory wells to test oil potential in the Niobrara formation
- Install compression at Juniper Draw and Yates Interstate (CBM)
- 45,400 net acres in the Wind River Basin of central Wyoming
- 99% average working interest
- 184 producing wells
- Production (Q3 net): 7 MBOED (61% liquids)
- Reserves (12/31/10): 30 MMBOE (40% liquids)
- Produces oil and gas from multiple formations at 1,000’ to 12,000’
- Producing assets include coalbed natural gas projects at Beaver Creek and Riverton Dome, conventional oil and gas and a CO2 enhanced oil recovery project in the Madison formation
- Actual capital expenditures: $65 million
- Drilled and completed 15 coalbed natural gas wells at Beaver Creek
- Recompleted 2 wells
- Began gas gathering system installation for coalbed natural gas development
- Produced and monitored Madison CO2 enhanced oil recovery project
- Acquired 3-D seismic
- Planned capital expenditures: ≈$25 million
- Operated rigs running: 0
- Perform select recompletions and workovers
- Evaluate new oil potential
- 157,500 net acres in the Washakie Basin of southern Wyoming
- 76% average working interest
- 1,260 producing wells
- Production (Q3 net): 24 MBOED (39% liquids)
- Reserves (12/31/10): 95 MMBOE (32% liquids)
- Produces gas from the multiple formations at 6,800’ to 10,300’
- Actual capital expenditures: $131 million
- Drilled and completed 97 wells
- Recompleted 12 wells
- Installed 63 plunger lifts
- Continued improved drilling efficiencies with new generation rigs and multi-well pad drilling
- Continued implementation of automated production control system
- Installed compression and performed other gas gathering system improvements
- Planned capital expenditures: ≈$90 million
- Operated rigs running: 1
- Drill ≈60 wells
- Recomplete 1 wells
- Continue to focus on achieving efficiencies through pad drilling and by further reducing drilling time
- Continue implementation of automated production control system
- 47,774 net acres in east-central Utah
- 44% average working interest
- 545 producing wells
- Production (Q3 net): 5 MBOED (0% liquids)
- Reserves (12/31/10): 22 MMBOE (0% liquids)
- Produces coalbed natural gas from the Ferron Coal formation at 2,800’ to 3,100’
- Actual capital expenditures: $4 million
- Drilled 4 coalbed natural gas wells
- Initiated implementation of automated production control system
- Planned capital expenditures: $3 million
- Operated rigs running: 0
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- 1,958,000 net acres
- 8,884 producing wells
- Production (Q3 net): 292 MBOED (23% liquids)
44% of Total Company
- Reserves (12/31/10): 1,441 MMBOE (24% liquids)
50% of Total Company
- 63,000 net acres in the Texas panhandle
- 48% average working interest
- 590 producing wells
- Production (Q3 net): 16 MBOED (44% liquids)
- Reserves (12/31/10): 40 MMBOE (33% liquids)
- Produces liquids-rich gas from multiple formations, including the prospective Cherokee and Granite Wash at 10,000’ to 18,000’
- Actual capital expenditures: $129 million
- Drilled and completed 29 horizontal wells
- Increased 2010 production 69% over 2009
- Reduced drilling time (spud to rig release) from 65 days in 2008 to 43 days in 2010
- Ramped up drilling activity from 1 to 3 operated rigs
- Analyzed well performance and horizon technical data to identify future development opportunities
- Planned capital expenditures: ≈$250 million
- Operated rigs running: 5
- Drill 55 wells
- Continue testing additional intervals to determine potential
- 243,000 net acres in the Anadarko Basin in western Oklahoma
- 52% average working interest
- 180 producing wells
- Production (Q3 net): 33 MBOED (24% liquids)
- Reserves (12/31/10): 175 MMBOE (34% liquids)
- Produces gas from the Woodford Shale formation at 10,500’ to 15,000’
- Actual capital expenditures: $718 million
- Drilled and completed 87 horizontal wells
- Increased 2010 production 177% over 2009
- Began 500’ offset infill pilot program
- Drilling focused on acreage evaluation and holding leases by establishing production
- Acquired additional seismic and acreage
- Installed 106 miles of gas gathering line
- Completed construction of 200 million cubic feet per day gas processing plant
- Planned capital expenditures: ≈$1,010 million
- Operated rigs running: 23
- Drill ≈225 horizontal wells
- Drill two additional 500’ infill pilot programs
- Continue drilling to hold leases by establishing production
- Acquire additional seismic
- Continue to expand gas gathering system capacity
- Install water distribution and recycling facility
- 43,000 net acres in the Arkoma Basin in eastern Oklahoma
- 31% average working interest
- 400 producing wells
- Production (Q3 net): 13 MBOED (22% liquids)
- Reserves (12/31/10): 48 MMBOE (19% liquids)
- Produces gas from the Woodford Shale formation at 6,000’ to 8,000’
- Actual capital expenditures: $95 million
- Drilled and completed 61 horizontal wells
- Purchased additional seismic
- Drilled longest lateral in an operated horizontal well to date of > 6,700’
- Planned capital expenditures: ≈$25 million
- Operated rigs running: 0
- Drill one non-operated horizontal wells
- Complete 22 wells drilled in 2010
- Reduce cost by implementing gathering system efficiencies
- 623,000 net acres in the Fort Worth Basin of north Texas
- 89% average working interest
- 4,600 producing wells
- Production (Q3 net): 216 MBOED (21% liquids)
- Reserves (12/31/10): 1,112 MMBOE (21% liquids)
- Produces gas from the Barnett Shale formation at 6,500’ to 9,200’
- Largest producer in the state’s largest natural gas field
- Actual capital expenditures: $1,079 million
- Drilled and completed 460 horizontal wells
- Achieved record net production of 1.2 billion cubic feet equivalent per day
- Reduced drilling time (spud to rig release) from 14.4 days in 2009 to 13.3 days in 2010
- Reduced drilling activity and focused on liquids-rich locations for economic considerations
- Planned capital expenditures: ≈$1,150 million
- Operated rigs running: 12
- Drill ≈375 horizontal wells
- Continue to focus on drilling liquids-rich locations
- Continue to focus on achieving efficiencies through pad drilling and by further reducing drilling time
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- 1,000,000 net acres
- 8,228 producing wells
- Production (Q3 net): 50 MBOED (75% liquids),
8% of Total Company
- Reserves (12/31/10): 167 MMBOE (77% liquids),
6% of Total Company
- 137,000 net acres in the Delaware Basin of southeast New Mexico and west Texas
- 77% average working interest
- 25 producing wells
- Production (Q3 net): 2 MBOED (60% liquids)
- Reserves (12/31/10): 4 MMBOE (55% liquids)
- Produces liquids-rich gas from the Avalon Shale formation at 6,000’ to 10,000’
- Emerging unconventional natural gas play
- Actual capital expenditures: $77 million
- Drilled and completed 19 horizontal wells
- Drilling focused on acreage evaluation
- Planned capital expenditures: ≈$145 million
- Operated rigs running: 1
- Drill ≈65 horizontal wells
- Continue to focus on acreage evaluation
- 150,000 net acres in southeast New Mexico and west Texas
- 78% average working interest
- Includes oil and gas production from the Delaware, Wolfcamp, Clearfork and Wichita Albany formations at 5,000’ to 8,500’
- Actual capital expenditures: $91 million
- Drilled and completed 67 horizontal wells
- Planned capital expenditures: ≈$100 million
- Operated rigs running: 2
- Drill 65 horizontal wells
- 183,000 net acres in the Delaware Basin of southeast New Mexico and west Texas
- 75% average working interest
- 12 producing wells
- Production (Q3 net): 5 MBOED (90% liquids)
- Reserves (12/31/10): 1 MMBOE (83% liquids)
- Produces oil from the Bone Spring formation at 8,000’ to 10,500’
- Production primarily from the 1st and 2nd Bone Spring formations in New Mexico and from the 3rd Bone Spring formation in Texas
- Actual capital expenditures: $16 million
- Drilled and completed 24 horizontal wells
- Drilling focused on acreage evaluation
- Planned capital expenditures: ≈$130 million
- Operated rigs running: 8
- Drill ≈40 horizontal wells
- Continue to focus on acreage evaluation
- Acquire additional acreage
- 160,000 net acres in the Midland Basin of west Texas
- 97% average working interest
- 196 producing wells
- Production (Q3 net): 10 MBOED (90% liquids)
- Reserves (12/31/10): 34 MMBOE (85% liquids)
- Produces oil from the Spraberry and Wolfcamp formations at 7,400’ to 10,400’
- Actual capital expenditures: $202 million
- Drilled and completed 89 vertical wells
- Drilling focused on acreage evaluation
- Acquired additional acreage
- Planned capital expenditures: ≈$240 million
- Operated rigs running: 4
- Drill ≈105 vertical wells
- Acquire additional acreage
- Begin 20-acre infill pilot
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- 1,270,000 net acres
- 4,359 producing wells
- Production (Q3 net): 70 MBOED (22% liquids)
11% of Total Company
- Reserves (12/31/10): 288 MMBOE (24% liquids)
10% of Total Company
- 204,000 net acres in east Texas
- 86% average working interest
- 1,725 producing wells
- Production (Q3 net): 35 MBOED (29% liquids)
- Reserves (12/31/10): 183 MMBOE (30% liquids)
- 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 12,600’
- Actual capital expenditures: $115 million
- Drilled and completed 27 wells, including 7 Cotton Valley horizontal wells
- Recompleted 9 wells
- Planned capital expenditures: ≈$190 million
- Operated rigs running: 2
- Drill 13 horizontal Cotton Valley wells
- Drill 11 vertical Cotton Valley wells
- Recomplete 11 wells
- 382,000 net acres in north Louisiana
- 50% average working interest
- 175 producing wells
- Production (Q3 net): 3 MBOED (15% liquids)
- Reserves (12/31/10): 12 MMBOE (12% liquids)
- Key areas include Ruston and Calhoun
- Produces oil and gas from multiple formations at 7,000’ to 17,000’
- Actual capital expenditures: $35 million
- Drilled and completed 2 horizontal wells
- Drilled and completed 3 vertical wells
- Recompleted 6 wells
- Planned capital expenditures: ≈$60 million
- Operated rigs running: 1
- Drill 5 horizontal wells
- Drill 1 vertical wells
- Recomplete 1 wells
- Acquire 3-D seismic
- 147,000 net acres in East Texas prospective for the Haynesville/Bossier shale, including 110,000 net acres in the Greater Carthage Area which is our primary focus area
- 92% average working interest
- 45 producing wells
- Production (Q3 net): 5 MBOED (13% liquids)
- Reserves (12/31/10): 11 MMBOE (6% liquids)
- Unconventional natural gas shale play
- Produces gas from the Haynesville and Bossier Shale formations at 10,400’ to 14,000’
- Actual capital expenditures: $276 million
- Drilled and completed 18 horizontal Haynesville wells
- Initiated drilling on 2 additional horizontal Haynesville wells; 4 wells are waiting on completion
- Drilled and completed 10 horizontal Bossier wells
- Planned capital expenditures: ≈$40 million
- Operated rigs running: 0
- Complete 4 horizontal Haynesville wells initiated in 2010
- Drill and complete 1 horizontal Haynesville wells
- Seek farm-out partners on primary term acreage
- 146,000 net acres in east central Texas
- 72% average working interest
- 740 producing wells
- Production (Q3 net): 14 MBOED (4% liquids)
- Reserves (12/31/10): 49 MMBOE (3% liquids)
- Key fields include Nan-Su-Gail, Personville, 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’
- Actual capital expenditures: $126 million
- Drilled and completed 8 horizontal wells
- Drilled and completed 7 vertical wells
- Recompleted 10 wells
- Planned capital expenditures: ≈$90 million
- Operated rigs running: 1
- Drill 9 horizontal wells
- Drill 2 vertical wells
- Recomplete 11 wells
- 252,000 net acres in east Texas
- 66% average working interest
- 910 producing wells
- Production (Q3 net): 13 MBOED (25% liquids)
- Reserves (12/31/10): 34 MMBOE (27% liquids)
- 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’
- Actual capital expenditures: $123 million
- Drilled and completed 6 horizontal Wilcox wells
- Drilled and completed 17 vertical wells
- Recompleted 27 wells
- Planned capital expenditures: ≈$130 million
- Operated rigs running: 2
- Drill 22 horizontal wells
- Drill 4 vertical wells
- Recomplete 32 wells
Overview
Devon Energy is a leading independent energy company engaged primarily in the exploration, development and production of natural gas and oil. The company’s operations are concentrated in various North American onshore areas that extend from the Canadian arctic to the Gulf Coast in the United States. Devon holds interests in nearly 13 million onshore acres, with over two-thirds undeveloped. This deep inventory of opportunities in premier North American growth plays will provide stable production and a platform for future growth.
Canada Overview
Devon is among the largest independent gas and oil producers in Canada. The company’s Canadian production is almost evenly split between natural gas and liquids. Devon’s Canadian oil production includes conventional resources, cold-flow heavy oil and thermal heavy oil. Many areas are restricted to winter-only access, which causes drilling activity to be concentrated in the coldest months.
The company’s future growth includes exploration and development opportunities in Canada’s most important energy-producing areas, including the Athabasca oil sands and the emerging shale gas play in the Horn River Basin of northeast British Columbia.
U.S. Overview
Devon’s operations in the United States are focused in four producing regions. Each region includes numerous producing fields with a vast inventory of undrilled locations. The company continues to explore for new resources from the expansive Rocky Mountains to the Gulf Coast of Texas and Louisiana. The Mid-Continent regions is home to three significant shale plays, the Arkoma Woodford Shale, Cana Woodford Shale and Devon’s largest producing field, the Barnett Shale. The Permian Basin and Gulf Coast regions provide stable production as well as meaningful exploration and development opportunities.
Foothills
Located along the east side of the Rockies, the Foothills region is one of Canada's most under-explored areas with high-impact, long-lived reserve potential. Since Devon's initial discovery in 1998 in the Grizzly area, the company has had considerable success in the region, which is characterized by both deep and shallow gas plays.
Deep Basin
Devon is one of the major producers in the Deep Basin, where the company has more than 500,000 net acres. Production from this liquids-rich area extends from central Alberta northwest along the edge of the Foothills.
Devon has used its large proprietary two-dimensional and three-dimensional seismic databases to build an extensive inventory of deep to mid-range drilling targets in this area. Most recently, the company has been testing light oil targets in the Cardium formation and liquids-rich opportunities in the lower Cretaceous zones, including the Cadomin.
The region has winter-only access restrictions in many areas, but offers year-round access in others. Devon controls significant gas processing and transportation infrastructure throughout the region and holds interests in the only major gas facilities in the Wapiti area. As results continue to impress, the Deep Basin remains a cornerstone of Canadian operations.
Horn River
The Horn River basin is situated in the far northeast of British Columbia and extends north into the Northwest Territories. The area’s Devonian and Triassic shale gas plays have similarities to the Barnett and other shale basins in the southern United States, which Devon and others are successfully developing.
Devon has a solid position in the Horn River Basin. The company is in the early stages of de-risking its acreage and is in the position to hold its acreage for many years as year-round roads and gas-gathering capabilities are expanded.
Northwest
Liquids rich gas and light gravity oil are the main products of this vast region which includes winter-only and all season access areas. Multi-zone drilling opportunities are common. Since initial exploration in the 1970s, the region has seen significant infrastructure expansion. Devon owns and operates gas gathering and processing facilities in the area, enabling projects to be brought on-stream quickly. The Swan Hills area is unique in that it contains the second-largest original oil-in-place accumulation in Western Canada, over 1.4 billion barrels of light-sour crude.
Lloydminster
Devon’s acreage in the Lloydminster region of eastern Alberta and west-central Saskatchewan produces predominantly conventional, cold flow, heavy oil and sweet, dry natural gas. The region is well-developed with significant infrastructure and is primarily accessible year-round for drilling. Lloydminster is a low-risk, high margin oil development play. The company has drilled over 1,800 wells in the area since 2003 and expects significant recompletion activity will take place into the future.
Pike
In March of 2010, Devon substantially increased its footprint in the Canadian oil sands by acquiring a 50 percent interest in BP’s Pike leases, in which it will act as operator. Combined with the Jackfish projects, Pike will allow Devon to grow its oil sands production to as much as 175,000 barrels per day by 2020. This low-risk oil production is a significant contributor to Devon’s future growth.
Jackfish
Devon’s heavy oil project at Jackfish uses a process called steam-assisted gravity drainage (SAGD) to extract bitumen from the Athabasca oil sands in eastern Alberta. Heat from a steam injection well liquefies very dense bitumen allowing it to flow to a production well located beneath. Devon saw first production from Jackfish, its first 35,000 barrel per day capacity project, in 2007. As measured by production per well and steam-to-oil ratio, Jackfish is one of Canada’s most commercially successful SAGD projects.
Construction of Jackfish 2, a look-alike 35,000 barrel per day capacity project began in the fall of 2008 and was completed in the first quarter of 2011. Devon began steam injection in the second quarter of 2011, and first oil is expected later in the year. Production will ramp up throughout 2012.
Review of Devon’s regulatory application for a third 35,000 barrel per day capacity Jackfish project is currently underway. Pending approval, the company expects to begin site work around year-end 2011 with plant startup targeted for 2015. Devon operates all the Jackfish projects and owns 100 percent working interest.
Peace River Arch
The Peace River Arch region, located along the British Columbia border in western Alberta, produces liquids-rich gas and light gravity oil. Multi-zone drilling opportunities from Cretaceous, Triassic, Devonian and Mississippian age formations are common in this area. Since initial exploitation in the 1970s, the region has seen significant infrastructure expansion. Devon owns and operates gas gathering and processing facilities in the area which enables our projects to be brought on production quickly. The Swan Hills area contains the second largest original oil-in-place accumulation in Western Canada, with over 1.4 billion barrels of light-sour crude.
Central
Devon’s Central region encompasses the central and southern plains of Alberta and Saskatchewan. This well-developed region produces crude oil and natural gas from multiple formations. The company is testing both the Viking light oil play on a subsection of its 900,000 acres of fee title lands in the Kindersley area of Saskatchewan and the Cardium light oil play in the Ferrier area of Alberta. Drilling access is generally year-round and the region is well-developed with significant Devon-operated infrastructure in place.
Rocky Mountains
Devon’s Rocky Mountain operations extend north from northern New Mexico up through parts of Colorado, Utah, Wyoming and Montana. The company’s assets in the Rocky Mountain region include interests in conventional oil and gas properties, as well as coalbed natural gas projects. Devon’s most important properties in the Rocky Mountains lie in the Washakie, Wind River, Big Horn, Green River and Powder River basins in Wyoming, the Bear Paw field in north-central Montana, and the Uinta Basin in Utah.
Bear Paw
Devon’s Bear Paw assets are located in north-central Montana. The reservoir is the Cretaceous age Eagle sand formation, which is a shoreline and deltaic deposit within the Western Interior Foreland Basin.
Powder River Basin
The Powder River Basin has historically been an oil producing basin. However, over the last decade Devon utilized its expertise, pioneered in the San Juan Basin, to focus on developing Powder River coalbed natural gas, an energy source produced from underground coal deposits. From its significant position in the basin, the company’s coalbed natural gas production reached an all-time high in 2010 of 120 million cubic feet per day. However, today the company has shifted its focus in the basin from coalbed drilling to oil exploration and development. Devon is currently testing several Cretaceous oil objectives, including the Parkman and Niobrara.
Wind River Basin
The Wind River basin is located in central Wyoming and produces from many different formations in more than 80 fields. The primary reservoirs include the Cretaceous Mesaverde coals, Frontier and Muddy sandstones, Permian age Phosphoria and the Pennsylvanian Tensleep sandstone. With the success of Devon’s Madison CO2 enhanced oil recovery project which has added over 3,500 barrels per day, evaluations of similar opportunities are underway.
Washakie
Devon has been among the most active drillers in the Washakie basin of southern Wyoming for many years. Targeting the Almond and Lewis formations, Devon produces approximately 140 million cubic feet of gas equivalent per day from this low-risk, tight sand gas play.
Drunkard's Wash
In 2008, Devon acquired an interest in the Drunkard’s Wash coalbed natural gas play in Utah. The field is located between the southern margin of the Uinta Basin, the eastern margin of the Wasatch Plateau and the western margin of the San Rafael Swell.
Mid-Continent
Devon’s Mid-Continent operations encompass Oklahoma, the Texas panhandle and north Texas. Devon’s most important Mid-Continent assets include the Barnett Shale in the Fort Worth Basin of north Texas, the Cana-Woodford Shale in western Oklahoma, the Arkoma-Woodford Shale in southeastern Oklahoma and the Granite Wash in the Texas panhandle. These fields represent many years of future growth with approximately 30 trillion cubic feet equivalent of net risked resource and nearly 15,000 undrilled locations.
Granite Wash
Another condensate and liquids-rich play for Devon is the Granite Wash in the Texas panhandle. In 2005, the company initiated a vertical drilling program targeting the multiple stacked conglomerate sandstones of the Granite Wash formation. Through this successful vertical program, optimum horizontal targets were identified leading to the company’s first operated horizontal in 2006.
Devon’s legacy land position in the Granite Wash is held by production and provides some of the best economics in the company’s portfolio. High initial production rates and strong liquid yields contribute to the superior full-cycle rates of return. The company continues to evaluate the additional potential of multiple untapped Granite Wash sands. If successful, this has the potential to significantly expand the size and scope of this exciting play.
Cana Woodford Shale
Leveraging its shale expertise, Devon established a significant first-mover position in the Cana Woodford Shale. The Cana Woodford in western Oklahoma is a leading growth area for Devon and has rapidly emerged as one of the most economic shale plays in North America. Only a few companies dominate the play. In 2010, Devon more than doubled its Cana acreage giving it the largest position in the play and holding more than 50% of the best acreage. The company’s current drilling activity is focused on evaluating its acreage and establishing production to hold leases.
The Cana Woodford Shale is especially attractive because of the liquids-rich nature of the gas. Some areas of play can yield upwards of 100 barrels of natural gas liquids per million cubic feet of natural gas produced. In addition to the high natural gas liquids content, the Cana Woodford offers a significant condensate component that further enhances drilling economics.
In 2011, Devon expects to roughly double its Cana production to 250 million cubic feet equivalent per day by year-end, including 14,000 barrels of natural gas liquids and condensate. With approximately 11 trillion cubic feet equivalent of risked resource potential and more than 5,000 risked locations remaining, the Cana provides many years of highly-economic production and reserve growth.
Arkoma Woodford Shale
Using expertise gained in the Barnett Shale, Devon also established a position in the Arkoma Woodford Shale located in southeast Oklahoma in the Arkoma basin. Most of Devon’s acreage is held by production and technical evaluation of the play has optimized economic returns from long-lateral horizontals.
Barnett Shale
The Barnett Shale, located in the Fort Worth Basin of north Texas, kicked-off shale gas production in North America and has emerged as the largest natural gas field in Texas. The Barnett Shale is a “tight” reservoir that does not allow gas to flow freely to the well bore. Hydraulic fracturing is required to release the trapped gas. After acquiring a substantial position in 2002, Devon was the first to apply horizontal drilling techniques in the Barnett, further enhancing production and transforming the Fort Worth Basin into one of the top producing gas fields in North America.
By virtue of its first mover position, Devon has acquired the largest and arguably the best acreage position in the play. Since 2002, the company has drilled more than 4,500 wells into the Barnett Shale. Devon is the most prolific producer in the Barnett, accounting for approximately 1.3 billion cubic feet of natural gas equivalent per day, which represents roughly one-quarter of the field’s total production.
The company continues to achieve outstanding results through pad drilling and improved drilling efficiencies. With risked resource potential of more than 17 trillion cubic feet of natural gas equivalent and thousands of undrilled locations, the Barnett provides Devon with many years of economic, organic growth.
Permian Basin
Devon’s operations in the Permian Basin of west Texas and southeast New Mexico provide the company with both oil and gas production. The Permian Basin was the source of some of the earliest oil and gas discoveries in the United States. It covers roughly 66,000 square miles and contains hundreds of oil and gas fields. Horizontal drilling and other technological advances are being used to unlock the vast resource that still remains.
The Permian Basin has been a legacy asset for Devon and continues to offer exploration and low-risk development opportunities from many geologic reservoirs and play types, including the condensate and liquids-rich Avalon Shale, oil-rich Wolfberry and Bone Spring and other conventional targets. These emerging oil and liquids-rich opportunities across Devon’s acreage in the Permian Basin will deliver high margin growth for many years to come.
Avalon Shale
The Avalon Shale (also referred to as the Leonard Shale) has become a very active play within the Delaware Basin because of the condensate and liquids-rich nature of the natural gas. The Avalon is a shaley unit located within the First Bone Spring formation. Horizontal wells are currently being drilled to develop this shale in New Mexico and extending into Texas. Although Devon is still in the early stages of evaluating its acreage in the play, initial drilling results indicate an attractive, repeatable play with outstanding economics.
Conventional Formations
Devon has an active drilling program in numerous conventional oil formations within the Permian Basin. Pay zones the company is targeting include the Delaware Sands present within the Delaware Basin, Wolfcamp Carbonates located along the Northwest Shelf, and Clearfork and Wolfcamp Carbonates deposited along the Central Basin Platform. The majority of the company’s acreage associated with these targets is legacy leasehold and held by existing production. Both lateral and vertical wells are being drilled to either in-fill or expand existing producing fields.
Bone Spring
The Bone Spring is a Permian age formation located in the Delaware Basin of west Texas and southeast New Mexico. The formation is comprised of three intervals, the First, Second and Third Bone Spring. Each are predominantly comprised of limestone, shale or sandstone. These three Bone Spring intervals are currently among the most active oil plays in the Permian Basin. While the Bone Spring has been a target for many years using conventional vertical drilling, new horizontal drilling techniques are now being applied to the formation with great success.
Wolfberry
The Wolfberry is an emerging light, sweet oil field in the Permian and Midland basins of west Texas. It consists of several geologic formations including the Permian Spraberry, Dean, Leonard and Wolfcamp. Since drilling its first Wolfberry well in 2008, Devon has significantly de-risked its acreage position. The company has identified approximately 1,000 low-risk vertical drilling locations in the play. Wolfberry drilling is especially attractive because of the high rates of return generated and the positive impact on cash flow.
Gulf Coast
Devon’s Gulf Coast operations cover more than one million net acres in south and east Texas, Louisiana and Mississippi. Most of the company’s production and reserves in the region come from long-lived oil and natural gas reservoirs found in conventional sandstone formations. Exploration and development activity in this area is enhanced by the stacked nature of these sandstone formations. Often wells drilled in the region can be completed in multiple pay zones, further enhancing economics. In recent years, the use of three-dimensional seismic technology and horizontal drilling techniques has unlocked new opportunities.
Carthage
Earliest development of the Carthage area in east Texas occurred from the mid-1930s through the 1940s with the drilling of the shallower, high permeability carbonate, gas-bearing Pettit intervals. Production dramatically increased with the development of the deeper Travis Peak sandstone intervals and Cotton Valley sands. Recent application of horizontal drilling and hydraulic fracturing in the Cotton Valley sand interval has been especially successful.
North Louisiana
The majority of Devon’s production in North Louisiana comes from the Hosston and Cotton Valley Sands also found in east Texas. Recent efforts have been focused on low-risk infill drilling and horizontal drilling for the Lower Cotton Valley sands. The company expects to pursue other liquids-rich horizontal drilling opportunities in the area.
Haynesville/Bossier Shale
Devon has 147,000 net acres in East Texas prospective for the Haynesville/Bossier shale formations. Devon is primarily focused in the Greater Carthage Area where it has 110,000 net acres. Since the majority of the company’s position was established before the play was discovered, Devon benefits from a low cost of entry. In addition, much of this acreage is held by existing production from other formations, whereby allowing Devon the option to pursue its Haynesville and Bossier Shale drilling when market conditions for dry gas improve. Exploration activities and production from the company’s 45 producing wells have confirmed large natural gas deposits and high reservoir pressures that support a repeatable economic play. With some 1,600 future drilling locations, the Haynesville and Bossier shale formations have significant future potential.
Groesbeck
The Groesbeck area is located on the west flank of the East Texas Basin. Early production from the Rodessa, Pettit and Travis Peak formations occurred in the late 1950s. Today, current practices include horizontal drilling and hydraulic fracturing in Bossier sands and Haynesville Lime intervals. When horizontal drilling is not feasible, vertical wells are drilled and production is commingled from multiple zones.
South Texas/South Louisiana
Devon’s south Texas properties are primarily located in Zapata, Webb and Matagorda counties in far southern Texas. Recent activity in these areas have focused on the Middle Wilcox/Lobo trend in Zapata and Webb counties and the Deep Frio trend in Matagorda county. The company has also had recent success with horizontal drilling in the Middle Wilcox formation in Webb county. Efforts are currently focused on identifying and extending horizontal drilling techniques to other suitable areas on the company’s south Texas acreage.