Devon Energy: An Overview and Breakdown of Our Earnings

Devon Energy Corporation (NYSE:DVN) today reported record net earnings for the year ended December 31, 2010, of $4.6 billion, or $10.35 per common share ($10.31 per diluted common share). This compares to a full-year 2009 net loss of $2.5 billion, or $5.58 per common share ($5.58 per diluted common share). The company’s 2009 financial results were impacted by a $4.2 billion non-cash, after-tax reduction in the carrying value of oil and gas properties.

For the quarter ended December 31, 2010, Devon reported net earnings of $562 million, or $1.30 per common share ($1.29 per diluted common share). In the fourth quarter of 2009, the company reported net earnings of $667 million, or $1.50 per common share ($1.49 per diluted common share).

Devon’s fourth-quarter 2010 financial results were impacted by certain items securities analysts typically exclude from their published estimates. Excluding these adjusting items, the company earned $683 million, or $1.57 per diluted common share. The adjusting items are discussed in detail later in this news release.

“2010 was an outstanding year for Devon. The company’s record earnings were accompanied by excellent operating results and the successful execution of our strategic repositioning,” commented John Richels, president and chief executive officer. “Our focused North American onshore capital program helped grow proved reserves to an all-time record of 2.9 billion equivalent barrels, and we are nearing completion of our strategic repositioning with total asset sales of more than $10 billion.”

Proved Oil and Gas Reserves Climb to Record Levels

In accordance with accounting standards, Devon’s year-end 2009 reserve balances include the reserves associated with the company’s Gulf of Mexico properties that were divested in 2010. Following is a discussion of proved reserves related only to Devon’s retained North American onshore assets, excluding the impact of the divested properties.

At year-end 2010, Devon’s North American onshore estimated proved reserves were a record 2,873 million oil-equivalent barrels (ASSET CLASS: E:BOE), a nine percent increase over year-end 2009. During 2010 Devon added 389 million oil-equivalent barrels through successful drilling (discoveries, extensions and performance revisions). Drill-bit capital applicable to its North American onshore properties totaled $6.1 billion, including $1.2 billion of unproved leasehold capture. Revisions related to changes in oil, natural gas, and natural gas liquids prices increased North American onshore proved reserves by an additional 71 million Boe.

Proved developed reserves were 2,042 million Boe at December 31, 2010, or 71 percent of total proved reserves. Year-end proved reserves were composed of 681 million barrels of crude oil, 10.3 trillion cubic feet of natural gas and 479 million barrels of natural gas liquids.

“Devon delivered outstanding results with our North American onshore drilling program in 2010,” said Dave Hager, executive vice president, exploration and production. “Our drill-bit reserve additions were 175 percent of our production output for the year. In addition, the reserves were added at very competitive finding costs in spite of adding $1.2 billion of unproved acreage during the year.”

Drill-bit Capital and Reserves Summary (1) Year Ended December 31,
North American Onshore
2010 2009
Drill-bit Capital (in millions) $ 6,123 $ 3,244
Reserves Data MMBoe
Extensions and discoveries 352 446
Revisions other than price 37 46
Drill-bit and performance reserve additions 389 492
(1) Detailed tables and non-GAAP reconciliations are also provided in this release.

Liquids Production Growth and Cana-Woodford Development Lead 2010 Operating Highlights

Devon drilled 1,588 wells in 2010 applicable to its continuing operations with a 99 percent success rate. Following are operational highlights from the past year:

  • Devon increased oil and natural gas liquids production from its North American onshore properties by six percent in 2010, to an average of 193,000 barrels per day.
  • During the year, Devon completed 87 wells in the Cana-Woodford Shale play in western Oklahoma and more than doubled its industry-leading leasehold position in the play to 243,000 net acres. Fourth-quarter production from the Cana-Woodford increased more than 200 percent over the year-ago quarter to an average of 137 million cubic feet of gas equivalent per day. The company also completed construction and commenced operation of its Cana gas processing plant in 2010.
  • In the Permian Basin, Devon increased fourth-quarter production 16 percent over the fourth quarter of 2009, to 45,000 Boe per day. Devon has nearly 1 million net acres of leasehold in the region targeting various oil and liquids-rich play types. In 2011, the company plans to run 17 operated rigs and drill approximately 300 wells to continue de-risking and developing these plays.
  • In 2010, production from the Devon-operated Jackfish oil sands project averaged 26,000 gross barrels per day or 25,000 barrels per day net to the company. Following scheduled facilities maintenance in the third quarter and the Enbridge pipeline system outage in the fourth quarter, Jackfish production ramped back up to 31,000 gross barrels per day at year-end.
  • Construction of the company’s second Jackfish project is now complete. Devon expects to begin injecting steam at Jackfish 2 in the second quarter, with first oil production expected by the end of 2011. Devon applied for regulatory approval of a third phase of Jackfish in the third quarter of 2010.
  • During the year, Devon added to its Canadian oil position by acquiring a 50 percent interest in the Pike oil sands leases. The Pike acreage lies immediately adjacent to the company’s highly successful Jackfish project and has estimated gross recoverable resources of up to 1.5 billion barrels. Devon is the operator of the project and is currently drilling appraisal wells to determine an optimal development configuration.
  • The company’s net production from the Barnett Shale field in north Texas averaged 1.2 billion cubic feet of natural gas equivalent per day in the fourth quarter, including 42,000 barrels per day of liquids production. This represents a 14 percent increase in production compared to fourth quarter of 2009.

Oil and Gas Sales Increase 19 Percent

Sales of oil, gas and natural gas liquids from continuing operations increased 19 percent to $7.3 billion in the year ended December 31, 2010. Comparable sales for the year ended December 31, 2009, were $6.1 billion. Devon’s average full-year 2010 realized price per Boe, including the impact of hedges, increased 26 percent over the prior year to $35.81 per barrel. Higher commodity prices more than offset a decrease in production resulting from the Gulf of Mexico properties that were divested during 2010.

Full-year 2010 production from the company’s North American onshore properties grew by 3 million Boe over the prior year to a total of 223 million oil-equivalent barrels. The improvement was driven entirely by higher oil and natural gas liquids production.

Devon’s fourth quarter production was impacted by a number of minor operational issues including volume curtailments attributable to the Enbridge pipeline outage, completion delays, and interruptions due to severe weather. In aggregate, these items reduced fourth quarter production by 11,000 equivalent barrels per day. In spite of these operational issues, North American onshore production in the fourth quarter averaged 619,000 Boe per day, an eight percent increase over the fourth quarter of 2009.

Repositioning Drives Cost Savings

Cost efficiencies realized through Devon’s strategic repositioning were reflected in the company’s 2010 results. In spite of a rising industry cost environment, expenses in most categories declined or increased only modestly.

Lease operating expenses LOE in 2010 increased one percent over 2009 to $1.7 billion. The increase in LOE is primarily attributable to the strengthening of the Canadian dollar. Devon’s divestiture of higher cost Gulf of Mexico properties helped offset the effects of rising oilfield service and supply costs.

Depreciation, depletion and amortization (DD&A) of oil and gas properties decreased nine percent in 2010 to $1.7 billion. The lower DD&A expense was primarily driven by the disposition of Devon’s Gulf of Mexico properties.

General and administrative expenses declined 13 percent in 2010 to $563 million. Lower employee costs related to the company’s strategic repositioning drove the improvement.

Interest expense in 2010 increased $14 million to $363 million. However, 2010 interest expense included a $19 million charge attributable to the early redemption of the company’s senior notes. Absent the early redemption charge, interest expense declined by $5 million when compared to 2009.

Cash Flow Before Balance Sheet Changes Increases 21 Percent;
Share Repurchases and Debt Reduction Total $3 Billion

Cash flow before balance sheet changes in 2010 reached $5.7 billion, a 21 percent increase over the prior year. During 2010, divestiture sale proceeds from the company’s strategic repositioning efforts provided an additional $7 billion of cash flow. In total, these sources of cash allowed Devon to fund its total capital demands, to repurchase 18.3 million shares of common stock for $1.2 billion, and to retire $1.8 billion of debt during the year.

As of December 31, 2010, the company’s cash balances totaled $3.4 billion, reducing net debt to 10 percent of adjusted capitalization compared with 29 percent at year-end 2009. Reconciliations of cash flow before balance sheet changes, net debt and adjusted capitalization, which are non-GAAP measures, are provided in this release.

Strategic Repositioning Nears Completion

In 2010, the company divested its Gulf of Mexico operations and closed on the sale of its assets in Azerbaijan and China for aggregate pre-tax proceeds of $7 billion. The company’s remaining divestiture package, consisting of its assets in Brazil, is under contract for $3.2 billion. Total proceeds for Devon’s strategic repositioning will exceed $10 billion with after-tax proceeds approximating $8 billion.

In accordance with accounting standards, Devon has reclassified the assets, liabilities, and results of its international segment as discontinued operations for all accounting periods presented in this release. Although revenues and expenses for prior periods were reclassified, previously reported net earnings were not impacted. Included with this release is a table of revenues, expenses, production categories, and the amounts reclassified as discontinued operations for each period presented.

Although Devon successfully completed the divestiture of its Gulf of Mexico operations, results from these assets do not qualify as discontinued operations under accounting standards and reside within continuing operations. However, information is provided within this release to enable the reader to isolate results of the company’s North American onshore operations.

Items Excluded from Published Earnings Estimates

Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company’s financial results. These items and their effects upon reported earnings for the full year and fourth quarter of 2010 were as follows:

Items affecting continuing operations:

  • A change in the fair value of oil, gas and NGL derivative instruments decreased full-year earnings by $77 million pre-tax ($50 million after tax) and decreased fourth-quarter earnings by $371 million pre-tax ($244 million after tax).
  • A change in fair value of interest-rate and other financial instruments decreased full-year earnings by $30 million pre-tax ($19 million after tax) and increased fourth-quarter earnings by $128 million pre-tax ($86 million after tax).
  • U.S. income taxes on foreign earnings now expected to be repatriated to the U.S. decreased full-year earnings by $144 million and decreased fourth-quarter earnings by $70 million.
  • Income tax accrual adjustments increased full-year earnings by $57 million and increased fourth-quarter earnings by $72 million.
  • Restructuring costs decreased full-year earnings by $57 million pre-tax ($36 million after tax) and decreased fourth-quarter earnings by $2 million pre-tax ($1 million after tax).
  • Additional interest expense attributable to the early redemption of 7.25 percent senior notes decreased full-year earnings by $19 million pre-tax ($12 million after tax).

Items affecting discontinued operations:

  • Divestitures of assets increased full-year earnings by $1.8 billion pre-tax ($1.8 billion after tax) and decreased fourth-quarter earnings by $25 million pre-tax and increased after-tax earnings by $20 million.
  • The decision to divest all international assets generated financial benefits that increased full-year earnings by $143 million pre-tax ($93 million after tax) and increased fourth-quarter earnings by $29 million pre-tax ($19 million after tax).
  • Insurance settlement proceeds related to a business interruption claim in Azerbaijan increased full-year earnings by $60 million pre-tax ($60 million after tax).
  • Restructuring costs increased full-year earnings by $4 million pre-tax ($3 million after tax) and decreased fourth-quarter earnings by $4 million pre-tax ($3 million after tax).

The following tables summarize the full-year and fourth-quarter effects of these items on 2010 earnings, income taxes and cash flow.

Full-Year 2010 – Summary of Items Typically Excluded by Analysts (in millions)
Continuing Operations Pre-tax
Earnings
Effect
After-tax
Earnings
Effect
Cash Flow Before
Balance Sheet
Changes Effect
Income Tax Effect
Current Deferred Total
Oil, gas, and NGL derivatives $ (77 ) (27 ) (27 ) (50 )
Interest-rate and other financial instruments (30 ) (11 ) (11 ) (19 )
U.S. income taxes on foreign earnings 144 144 (144 )
Income tax accrual adjustment (329 ) 272 (57 ) 57 329
Restructuring costs (57 ) 8 (29 ) (21 ) (36 ) (64 )
Additional interest costs on debt retirement (19 ) (10 ) 3 (7 ) (12 ) (17 )
Effects of oil and gas property divestitures 783 (783 ) (783 )
Totals $ (183 ) 452 (431 ) 21 (204 ) (535 )
Discontinued Operations Pre-tax
Earnings
Effect
After-tax
Earnings
Effect
Cash Flow Before
Balance Sheet
Changes Effect
Income Tax Effect
Current Deferred Total
Effects of oil and gas property divestitures $ 1,818 84 (43 ) 41 1,777 (84 )
Financial benefits of decision to divest assets 143 50 50 93
Insurance settlement 60 60 60
Restructuring costs 4 1 1 3 (2 )
Totals $ 2,025 85 7 92 1,933 (26 )

In aggregate, these items increased full-year 2010 net earnings by $1.7 billion, or $3.94 per common share ($3.92 per diluted share). These items and their associated tax effects decreased full-year 2010 cash flow before balance sheet changes by $561 million.

Fourth-Quarter 2010 – Summary of Items Typically Excluded by Analysts (in millions)
Continuing Operations Pre-tax
Earnings
Effect
After-tax
Earnings
Effect
Cash Flow Before
Balance Sheet
Changes Effect
Income Tax Effect
Current Deferred Total
Oil, gas, and NGL derivatives $ (371 ) (127 ) (127 ) (244 )
Interest-rate and other financial instruments 128 42 42 86
U.S. income taxes on foreign earnings 70 70 (70 )
Income tax accrual adjustment (72 ) (72 ) 72 72
Restructuring costs (2 ) (1 ) (1 ) (1 ) (1 )
Totals $ (245 ) (73 ) (15 ) (88 ) (157 ) 71
Discontinued Operations Pre-tax
Earnings
Effect
After-tax
Earnings
Effect
Cash Flow Before
Balance Sheet
Changes Effect
Income Tax Effect
Current Deferred Total
Effects of oil and gas property divestitures (25 ) (45 ) (45 ) 20 45
Financial benefits of decision to divest assets $ 29 10 10 19
Restructuring costs (4 ) (1 ) (1 ) (3 ) (4 )
Totals $ (46 ) 10 (36 ) 36 41

In aggregate, these items decreased fourth-quarter 2010 net earnings by $121 million, or $0.28 per common share ($0.28 per diluted share). These items and their associated tax effects increased fourth-quarter 2010 cash flow before balance sheet changes by $112 million.

Conference Call to be Webcast Today

Devon will discuss its 2010 financial and operating results in a conference call webcast today. The webcast will begin at 10 a.m. Central Time (11 a.m. Eastern Time). The webcast may be accessed from Devon’s Internet home page at www.devonenergy.com.

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION

PRODUCTION (net of royalties) Year Ended Quarter Ended
Excludes discontinued operations December 31, December 31,
2010 2009 2010 2009
Total Period Production
Natural Gas (ASSET CLASS::BCF)
U.S. Onshore 698.5 698.7 180.6 162.8
Canada 214.2 222.8 52.6 51.6
North American Onshore 912.7 921.5 233.2 214.4
U.S. Offshore 16.8 44.9 11.4
Total Natural Gas 929.5 966.4 233.2 225.8
Oil MMBbls
U.S. Onshore 13.5 11.6 3.7 2.9
Canada 25.2 25.3 6.1 6.6
North American Onshore 38.7 36.9 9.8 9.5
U.S. Offshore 1.9 5.0 1.3
Total Oil 40.6 41.9 9.8 10.8
Natural Gas Liquids MMBbls
U.S. Onshore 28.2 25.7 7.4 6.5
Canada 3.6 3.8 0.9 1.0
North American Onshore 31.8 29.5 8.3 7.5
U.S. Offshore 0.3 0.7 0.2
Total Natural Gas Liquids 32.1 30.2 8.3 7.7
Oil Equivalent MMBoe
U.S. Onshore 158.2 153.7 41.2 36.5
Canada 64.4 66.3 15.7 16.2
North American Onshore 222.6 220.0 56.9 52.7
U.S. Offshore 5.0 13.2 3.4
Total Oil Equivalent 227.6 233.2 56.9 56.1
Average Daily Production
Natural Gas MMcf
U.S. Onshore 1,913.8 1,914.3 1,963.0 1,769.7
Canada 586.9 610.5 571.7 560.5
North American Onshore 2,500.7 2,524.8 2,534.7 2,330.2
U.S. Offshore 46.0 123.0 123.8
Total Natural Gas 2,546.7 2,647.8 2,534.7 2,454.0
Oil MBbls
U.S. Onshore 37.0 31.6 40.0 31.3
Canada 68.9 69.3 66.0 72.0
North American Onshore 105.9 100.9 106.0 103.3
U.S. Offshore 5.2 13.8 13.7
Total Oil 111.1 114.7 106.0 117.0
Natural Gas Liquids MBbls
U.S. Onshore 77.3 70.4 80.8 71.1
Canada 9.8 10.4 9.2 10.2
North American Onshore 87.1 80.8 90.0 81.3
U.S. Offshore 0.9 2.0 2.2
Total Natural Gas Liquids 88.0 82.8 90.0 83.5
Oil Equivalent MBoe
U.S. Onshore 433.3 421.1 448.0 397.4
Canada 176.5 181.5 170.5 175.6
North American Onshore 609.8 602.6 618.5 573.0
U.S. Offshore 13.8 36.3 36.5
Total Oil Equivalent 623.6 638.9 618.5 609.5
BENCHMARK PRICES Year Ended Quarter Ended
(average prices) December 31, December 31,
2010 2009 2010 2009
Natural Gas ($/Mcf) – Henry Hub $ 4.39 $ 3.99 $ 3.80 $ 4.16
Oil ($/Bbl) – West Texas Intermediate (Cushing) $ 79.48 $ 61.82 $ 85.15 $ 76.00
Quarter Ended December 31, 2010 Oil Gas NGLs Total
(Per Bbl) (Per Mcf) (Per Bbl) (Per Boe)
U.S. Onshore $ 80.79 $ 3.21 $ 33.19 $ 27.27
Canada $ 60.80 $ 3.69 $ 47.46 $ 38.46
North American Onshore $ 68.35 $ 3.32 $ 34.65 $ 30.36
U.S. Offshore $ $ $ $
Realized price without hedges $ 68.35 $ 3.32 $ 34.65 $ 30.36
Cash settlements $ $ 1.32 $ $ 5.41
Realized price, including cash settlements $ 68.35 $ 4.64 $ 34.65 $ 35.77
Quarter Ended December 31, 2009 Oil Gas NGLs Total
(Per Bbl) (Per Mcf) (Per Bbl) (Per Boe)
U.S. Onshore $ 71.62 $ 3.65 $ 30.48 $ 27.35
Canada $ 58.43 $ 4.13 $ 41.88 $ 39.58
North American Onshore $ 62.43 $ 3.77 $ 31.92 $ 31.10
U.S. Offshore $ 74.45 $ 4.45 $ 37.59 $ 45.26
Realized price without hedges $ 63.84 $ 3.80 $ 32.07 $ 31.95
Cash settlements $ $ 0.65 $ $ 2.60
Realized price, including cash settlements $ 63.84 $ 4.45 $ 32.07 $ 34.55
Year Ended December 31, 2010 Oil Gas NGLs Total
(Per Bbl) (Per Mcf) (Per Bbl) (Per Boe)
U.S. Onshore $ 75.53 $ 3.73 $ 30.78 $ 28.42
Canada $ 58.60 $ 4.11 $ 46.60 $ 39.11
North American Onshore $ 64.51 $ 3.82 $ 32.55 $ 31.52
U.S. Offshore $ 77.81 $ 5.12 $ 38.22 $ 49.06
Realized price without hedges $ 65.14 $ 3.84 $ 32.61 $ 31.91
Cash settlements $ $ 0.96 $ $ 3.90
Realized price, including cash settlements $ 65.14 $ 4.80 $ 32.61 $ 35.81
Year Ended December 31, 2009 Oil Gas NGLs Total
(Per Bbl) (Per Mcf) (Per Bbl) (Per Boe)
U.S. Onshore $ 56.17 $ 3.14 $ 23.40 $ 22.41
Canada $ 47.35 $ 3.66 $ 33.09 $ 32.29
North American Onshore $ 50.11 $ 3.27 $ 24.65 $ 25.38
U.S. Offshore $ 60.75 $ 4.20 $ 27.42 $ 38.83
Realized price without hedges $ 51.39 $ 3.31 $ 24.71 $ 26.15
Cash settlements $ $ 0.52 $ $ 2.16
Realized price, including cash settlements $ 51.39 $ 3.83 $ 24.71 $ 28.31
CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended Quarter Ended
(in millions, except per share amounts) December 31, December 31,
2010 2009 2010 2009
Revenues
Oil, gas, and NGL sales $ 7,262 $ 6,097 $ 1,727 $ 1,791
Oil, gas, and NGL derivatives 811 384 (63 ) 194
Marketing and midstream revenues 1,867 1,534 471 460
Total revenues 9,940 8,015 2,135 2,445
Expenses and other, net
Lease operating expenses 1,689 1,670 418 404
Taxes other than income taxes 380 314 92 65
Marketing and midstream operating costs and expenses 1,357 1,022 344 327
Depreciation, depletion and amortization of oil and gas properties 1,675 1,832 426 418
Depreciation and amortization of non-oil and gas properties 255 276 63 68
Accretion of asset retirement obligation 92 91 21 23
General and administrative expenses 563 648 164 176
Restructuring costs 57 105 2 105
Interest expense 363 349 83 86
Interest-rate and other financial instruments (14 ) (106 ) (135 ) (86 )
Reduction of carrying value of oil and gas properties 6,408
Other, net (45 ) (68 ) (11 ) (7 )
Total expenses and other, net 6,372 12,541 1,467 1,579
Earnings loss from continuing operations before income tax expense 3,568 (4,526 ) 668 866
Income tax expense (benefit)
Current 516 241 (180 ) 106
Deferred 719 (2,014 ) 370 203
Total income tax expense (benefit) 1,235 (1,773 ) 190 309
Earnings loss from continuing operations 2,333 (2,753 ) 478 557
Discontinued operations
Earnings from discontinued operations before income taxes 2,385 322 65 124
Discontinued operations income tax expense (benefit) 168 48 (19 ) 14
Earnings from discontinued operations 2,217 274 84 110
Net earnings loss $ 4,550 $ (2,479 ) $ 562 $ 667
Basic net earnings loss per share
Basic earnings loss from continuing operations per share $ 5.31 $ (6.20 ) $ 1.10 $ 1.25
Basic earnings from discontinued operations per share 5.04 0.62 0.20 0.25
Basic net earnings loss per share $ 10.35 $ (5.58 ) $ 1.30 $ 1.50
Diluted net earnings loss per share
Diluted earnings loss from continuing operations per share $ 5.29 $ (6.20 ) $ 1.10 $ 1.25
Diluted earnings from discontinued operations per share 5.02 0.62 0.19 0.24
Diluted net earnings loss per share $ 10.31 $ (5.58 ) $ 1.29 $ 1.49
Weighted average common shares outstanding
Basic 440 444 433 445
Diluted 441 446 434 447
CONSOLIDATED BALANCE SHEETS
(in millions) December 31, December 31,
2010 2009
Assets
Current assets:
Cash and cash equivalents $ 2,866 $ 646
Accounts receivable 1,202 1,208
Current assets held for sale 563 657
Other current assets 924 481
Total current assets 5,555 2,992
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization 56,012 52,352
Not subject to amortization 3,434 4,078
Total oil and gas 59,446 56,430
Other 4,429 4,045
Total property and equipment, at cost 63,875 60,475
Less accumulated depreciation, depletion and amortization (44,223 ) (41,708 )
Property and equipment, net 19,652 18,767
Goodwill 6,080 5,930
Long-term assets held for sale 859 1,250
Other long-term assets 781 747
Total Assets $ 32,927 $ 29,686
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable – trade $ 1,411 $ 1,137
Revenues and royalties due to others 538 486
Short-term debt 1,811 1,432
Current liabilities associated with assets held for sale 305 234
Other current liabilities 518 513
Total current liabilities 4,583 3,802
Long-term debt 3,819 5,847
Asset retirement obligations 1,423 1,418
Liabilities associated with assets held for sale 26 213
Other long-term liabilities 1,067 937
Deferred income taxes 2,756 1,899
Stockholders’ equity:
Common stock 43 45
Additional paid-in capital 5,601 6,527
Retained earnings 11,882 7,613
Accumulated other comprehensive earnings 1,760 1,385
Treasury stock, at cost (33 )
Total Stockholders’ Equity 19,253 15,570
Total Liabilities and Stockholders’ Equity $ 32,927 $ 29,686
Common Shares Outstanding 432 447
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions) Year Ended Quarter Ended
December 31, December 31,
2010 2009 2010 2009
Cash Flows From Operating Activities
Earnings loss from continuing operations $ 2,333 $ (2,753 ) $ 478 $ 557
Adjustments to reconcile earnings loss from continuing
operations to net cash provided by operating activities:
Depreciation, depletion and amortization 1,930 2,108 489 486
Deferred income tax expense (benefit) 719 (2,014 ) 370 203
Reduction of carrying value of oil and gas properties 6,408
Unrealized change in fair value of financial instruments 107 55 243 (129 )
Other noncash charges 215 288 61 106
Net cash from operating activities before balance sheet changes 5,304 4,092 1,641 1,223
Net (increase) decrease in working capital (273 ) 149 (437 ) 68
Decrease (increase) in long-term other assets 32 (6 ) 4 (23 )
(Decrease) increase in long-term other liabilities (41 ) (3 ) (98 ) 29
Cash from operating activities – continuing operations 5,022 4,232 1,110 1,297
Cash from operating activities – discontinued operations 456 505 132 148
Net cash from operating activities 5,478 4,737 1,242 1,445
Cash Flows From Investing Activities
Proceeds from property and equipment divestitures 4,310 34 179 11
Capital expenditures (6,476 ) (4,879 ) (1,683 ) (1,072 )
Purchases of short-term investments (145 ) (145 )
Redemptions of long-term investments 21 7 1 1
Other (19 ) (17 ) (6 ) (17 )
Cash from investing activities – continuing operations (2,309 ) (4,855 ) (1,654 ) (1,077 )
Cash from investing activities – discontinued operations 2,197 (499 ) (101 ) (123 )
Net cash from investing activities (112 ) (5,354 ) (1,755 ) (1,200 )
Cash Flows From Financing Activities
Net commercial paper (repayments) borrowings (1,432 ) 426 63
Debt repayments (350 ) (178 ) (177 )
Proceeds from borrowings of long term debt, net of issuance costs 1,187
Proceeds from stock option exercises 111 42 93 23
Repurchases of common stock (1,168 ) (239 )
Dividends paid on common stock (281 ) (284 ) (70 ) (71 )
Excess tax benefits related to share-based compensation 16 8 9 2
Net cash from financing activities (3,104 ) 1,201 (207 ) (46 )
Effect of exchange rate changes on cash 17 43 12 14
Net increase (decrease) in cash and cash equivalents 2,279 627 (708 ) 99
Cash and cash equivalents at beginning of period 1,011 384 3,998 912
Cash and cash equivalents at end of period $ 3,290 $ 1,011 $ 3,290 $ 1,011
RESERVES RECONCILIATION
Total North American Onshore
Oil Gas NGLs Total Oil Gas NGLs Total
MMBbls (ASSET CLASS::BCF) MMBbls MMBoe MMBbls (ASSET CLASS::BCF) MMBbls MMBoe
As of December 31, 2009:
Proved developed 289 7,845 326 1,922 268 7,660 325 1,869
Proved undeveloped 397 1,912 95 811 385 1,755 94 772
Total proved 686 9,757 421 2,733 653 9,415 419 2,641
Revisions due to prices (19 ) 472 13 72 (20 ) 470 13 71
Revisions other than price 13 62 15 38 11 88 12 37
Extensions and discoveries 79 1,226 70 354 78 1,219 70 352
Purchase of reserves 21 4 21 4
Production (41 ) (930 ) (32 ) (228 ) (39 ) (913 ) (32 ) (223 )
Sale of reserves (37 ) (325 ) (8 ) (100 ) (2 ) (17 ) (3 ) (9 )
As of December 31, 2010:
Proved developed 257 8,424 381 2,042 257 8,424 381 2,042
Proved undeveloped 424 1,859 98 831 424 1,859 98 831
Total Proved 681 10,283 479 2,873 681 10,283 479 2,873
U.S. Onshore Canada
Oil Gas NGLs Total Oil Gas NGLs Total
MMBbls (ASSET CLASS::BCF) MMBbls MMBoe MMBbls (ASSET CLASS::BCF) MMBbls MMBoe
As of December 31, 2009:
Proved developed 119 6,447 293 1,486 149 1,213 32 383
Proved undeveloped 20 1,680 92 392 365 75 2 380
Total proved 139 8,127 385 1,878 514 1,288 34 763
Revisions due to prices 4 449 14 92 (24 ) 21 (1 ) (21 )
Revisions other than price 2 105 13 32 9 (17 ) (1 ) 5
Extensions and discoveries 19 1,088 68 269 59 131 2 83
Purchase of reserves 12 2 9 2
Production (14 ) (699 ) (28 ) (158 ) (25 ) (214 ) (4 ) (65 )
Sale of reserves (2 ) (17 ) (3 ) (8 ) (1 )
As of December 31, 2010:
Proved developed 131 7,280 353 1,696 126 1,144 28 346
Proved undeveloped 17 1,785 96 411 407 74 2 420
Total Proved 148 9,065 449 2,107 533 1,218 30 766
U.S. Offshore
Oil Gas NGLs Total
MMBbls (ASSET CLASS::BCF) MMBbls MMBoe
As of December 31, 2009:
Proved developed 21 185 1 53
Proved undeveloped 12 157 1 39
Total proved 33 342 2 92
Revisions due to prices 1 2 1
Revisions other than price 2 (26 ) 3 1
Extensions and discoveries 1 7 2
Purchase of reserves
Production (2 ) (17 ) (5 )
Sale of reserves (35 ) (308 ) (5 ) (91 )
As of December 31, 2010:
Proved developed
Proved undeveloped
Total Proved
COSTS INCURRED Total North American Onshore
(in millions) Year Ended December 31, Year Ended December 31,
2010 2009 2010 2009
Property Acquisition Costs:
Total proved $ 33 $ 35 $ 33 $ 35
Total unproved 1,184 135 1,182 124
Exploration and development costs 5,327 3,917 4,941 3,120
Costs Incurred $ 6,544 $ 4,087 $ 6,156 $ 3,279
U.S. Onshore Canada
Year Ended December 31, Year Ended December 31,
2010 2009 2010 2009
Property Acquisition Costs:
Total proved $ 29 $ 17 $ 4 $ 18
Total unproved 592 52 590 72
Exploration and development costs 3,465 2,133 1,476 987
Costs Incurred $ 4,086 $ 2,202 $ 2,070 $ 1,077
U.S. Offshore
Year Ended December 31,
2010 2009
Property Acquisition Costs:
Total proved $ $
Total unproved 2 11
Exploration and development costs 386 797
Costs Incurred $ 388 $ 808

Devon capitalizes certain general and administrative expenses related to property acquisition, exploration and development activities. These capitalized expenses were $311 million and $332 million in 2010 and 2009, respectively. Devon also capitalizes certain interest expenses related to property acquisition, exploration and development activities. These capitalized expenses were $37 million and $74 million in 2010 and 2009, respectively. These capitalized general and administrative expenses and interest expenses are included in the costs shown in the preceding tables.

DRILLING ACTIVITY Year Ended
(Gross Wells Drilled) December 31,
2010 2009
Exploration Wells Drilled
U.S. Onshore 34 11
Canada 57 42
North American Onshore 91 53
U.S. Offshore 1
Total 91 54
Exploration Wells Success Rate
U.S. Onshore 91 % 82 %
Canada 98 % 100 %
North American Onshore 95 % 96 %
U.S. Offshore n/a 0 %
Total 95 % 94 %
Development Wells Drilled
U.S. Onshore 1,180 734
Canada 313 343
North American Onshore 1,493 1,077
U.S. Offshore 4 4
Total 1,497 1,081
Development Wells Success Rate
U.S. Onshore 99 % 100 %
Canada 100 % 100 %
North American Onshore 100 % 100 %
U.S. Offshore 100 % 50 %
Total 100 % 99 %
Total Wells Drilled
U.S. Onshore 1,214 745
Canada 370 385
North American Onshore 1,584 1,130
U.S. Offshore 4 5
Total 1,588 1,135
Total Wells Success Rate
U.S. Onshore 99 % 99 %
Canada 100 % 100 %
North American Onshore 99 % 99 %
U.S. Offshore 100 % 40 %
Total 99 % 99 %
COMPANY OPERATED RIGS Year Ended
December 31,
2010 2009
Number of Company Operated Rigs Running
U.S. Onshore 61 46
Canada 10 17
North American Onshore 71 63
U.S. Offshore 1
Total 71 64
CAPITAL EXPENDITURES (in millions)
Quarter Ended December 31, 2010
U.S. Canada N.A. U.S. Total
Onshore Onshore Offshore
Capital Expenditures
Exploration $ 246 64 $ 310 $ 310
Development 917 430 1,347 10 1,357
Exploration and development capital $ 1,163 494 $ 1,657 10 $ 1,667
Capitalized G&A 79
Capitalized interest 12
Midstream capital 51
Other capital 111
Total Continuing Operations $ 1,920
Discontinued operations 63
Total Operations $ 1,983
CAPITAL EXPENDITURES (in millions)
Year Ended December 31, 2010
U.S. Canada N.A. U.S. Total
Onshore Onshore Offshore
Capital Expenditures
Exploration $ 899 322 $ 1,221 97 $ 1,318
Development 2,897 1,062 3,959 258 4,217
Exploration and development capital $ 3,796 1,384 $ 5,180 355 $ 5,535
Pike property acquisition 500
Capitalized G&A 311
Capitalized interest 40
Midstream capital 220
Other capital 313
Total Continuing Operations $ 6,919
Discontinued operations 481
Total Operations $ 7,400
PRODUCTION FROM DISCONTINUED OPERATIONS Year Ended Quarter Ended
December 31, December 31,
2010 2009 2010 2009
Oil MMBbls 9.3 15.7 1.5 4.1
Natural Gas (ASSET CLASS::BCF) 1.3 1.5 0.5
Total Oil Equivalent MMBoe 9.5 16.0 1.5 4.2
STATEMENTS OF DISCONTINUED OPERATIONS
(in millions) Year Ended Quarter Ended
December 31, December 31,
2010 2009 2010 2009
Revenues
Total operating revenues $ 693 $ 945 $ 120 $ 299
Expenses and other, net
Operating expenses 212 496 36 131
Gain on sale of oil and gas properties (1,818) (17) 26
Other, net (86) 144 (7) 44
Total expenses and other, net (1,692) 623 55 175
Earnings before income tax expense 2,385 322 65 124
Income tax expense (benefit)
Current 195 44 5 24
Deferred (27) 4 (24) (10)
Total income tax expense (benefit) 168 48 (19) 14
Earnings from discontinued operations $ 2,217 $ 274 $ 84 $ 110
RESERVES DATA FOR DISCONTINUED OPERATIONS
Oil Gas NGLs Total
MMBbls (ASSET CLASS::BCF) MMBbls MMBoe
As of December 31, 2009:
Proved developed 54 8 55
Proved undeveloped 53 53
Total proved 107 8 108
Revisions due to prices (3 ) (3 )
Revisions other than price (7 ) (1 )
Extensions and discoveries 2 2
Production (10 ) (1 ) (10 )
Sale of reserves (89 ) (89 )
As of December 31, 2010:
Proved developed 7 7
Proved undeveloped
Total proved 7 7
COSTS INCURRED FOR DISCONTINUED OPERATIONS
(in millions) Year Ended December 31,
2010 2009
Costs Incurred $ 470 $ 450

NON-GAAP FINANCIAL MEASURES

The United States Securities and Exchange Commission has adopted disclosure requirements for public companies such as Devon concerning Non-GAAP financial measures. (GAAP refers to generally accepted accounting principles.) The company must reconcile the Non-GAAP financial measure to related GAAP information. Cash flow before balance sheet changes is a Non-GAAP financial measure. Devon believes cash flow before balance sheet changes is relevant because it is a measure of cash available to fund the company’s capital expenditures, dividends and to service its debt. Cash flow before balance sheet changes is also used by certain securities analysts as a measure of Devon’s financial results.

RECONCILIATION TO GAAP INFORMATION Year Ended Quarter Ended
(in millions) December 31, December 31,
2010 2009 2010 2009
Net Cash Provided By Operating Activities GAAP $ 5,478 $ 4,737 $ 1,242 $ 1,445
Changes in assets and liabilities – continuing operations 282 (140 ) 531 (74 )
Changes in assets and liabilities – discontinued operations (88 ) 90 (50 ) 15
Cash flow before balance sheet changes (Non-GAAP) $ 5,672 $ 4,687 $ 1,723 $ 1,386

Devon believes that using net debt for the calculation of “net debt to adjusted capitalization” provides a better measure than using debt. Devon defines net debt as debt less cash, cash equivalents and short-term investments. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash to repay debt.

RECONCILIATION TO GAAP INFORMATION
(in millions)
December 31,
2010 2009
Total debt GAAP $ 5,630 $ 7,279
Adjustments:
Cash and short term investments 3,435 1,011
Net debt (Non-GAAP) $ 2,195 $ 6,268
Total debt $ 5,630 $ 7,279
Stockholders’ equity 19,253 15,570
Total capitalization GAAP $ 24,883 $ 22,849
Net debt $ 2,195 $ 6,268
Stockholders’ equity 19,253 15,570
Adjusted capitalization (Non-GAAP) $ 21,448 $ 21,838

NON-GAAP FINANCIAL MEASURES

Drill-bit capital is defined as costs incurred less proved acquisition costs and unproved acquisition costs resulting from business combinations. Drill-bit capital is a Non-GAAP measure. Devon believes drill-bit capital is relevant because it provides additional insight into costs associated with current year exploration and development activities. Certain securities analysts also use this methodology to measure Devon’s performance. It should be noted that the actual costs of reserves added through Devon’s drilling program will differ, sometimes significantly, from the direct comparison of capital spent and reserves added in any given period due to the timing of capital expenditures and reserve bookings.

RECONCILIATION TO GAAP INFORMATION Total North America Onshore
(in millions) Year Ended December 31, Year Ended December 31,
2010 2009 2010 2009
Costs Incurred GAAP $ 6,544 $ 4,087 $ 6,156 $ 3,279
Less:
Proved acquisition costs 33 35 33 35
Drill-bit capital (Non-GAAP) $ 6,511 $ 4,052 $ 6,123 $ 3,244
U.S. Onshore Canada
Year Ended December 31, Year Ended December 31,
2010 2009 2010 2009
Costs Incurred GAAP $ 4,086 $ 2,202 $ 2,070 $ 1,077
Less:
Proved acquisition costs 29 17 4 18
Drill-bit capital (Non-GAAP) $ 4,057 $ 2,185 $ 2,066 $ 1,059
U.S. Offshore
Year Ended December 31,
2010 2009
Costs Incurred GAAP $ 388 $ 808
Less:
Proved acquisition costs
Drill-bit capital (Non-GAAP) $ 388 $ 808

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