Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” of this report.

Overview of 2013 Results

As an enterprise, we strive to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by executing our strategy, which is outlined in “Items 1 and 2. Business and Properties” of this report.

2013 was another year of strong execution and exciting change for Devon. Our oil-focused drilling programs not only accomplished impressive oil production growth, but also expanded margins and improved operating cash flow. Additionally, we took steps to high-grade our portfolio. We did this by announcing an accretive Eagle Ford Shale acquisition, an innovative midstream combination, and the initiation of an asset divestiture program. These actions will provide the platform from which we will deliver outstanding high-margin growth in 2014 and for many years to come.

Key measures of our 2013 performance are summarized below, which exclude amounts from our discontinued operations.

		Year Ended December 31,
		2013				Change				2012				Change				2011
		($ in millions, except per share amounts)
Net earnings (loss)		$	(20	)			+89	%		$	(185	)			-109	%		$	2,134
Adjusted earnings (1)		$	1,734				+33	%		$	1,305				-49	%		$	2,578
Earnings (loss) per share		$	(0.06	)			+87	%		$	(0.47	)			-109	%		$	5.10
Adjusted earnings per share (1)		$	4.26				+32	%		$	3.22				-48	%		$	6.17
Production (MBoe/d)			692.9				+2	%			682.3				+4	%			657.7
Realized price per Boe		$	33.70				+18	%		$	28.65				-17	%		$	34.64
Adjusted operating income per Boe (2)		$	19.86				+2	%		$	19.41				-23	%		$	25.11
Operating cash flow		$	5,436				+10	%		$	4,930				-21	%		$	6,246
Capitalized costs		$	6,643				-22	%		$	8,474				+9	%		$	7,795
Shareholder distributions (3)		$	348				+8	%		$	324				-88	%		$	2,610
Reserves (MMBoe)			2,963				0	%			2,963				-1	%			3,005

(1)

Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are not financial measures prepared in accordance with accounting principles generally accepted in the United States (GAAP). For a description of adjusted earnings, adjusted earnings per share and adjusted operating cash flow as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.

(2)	Computed as revenues from commodity sales, commodity derivatives settlements, and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administration, taxes other than income taxes and interest, with the result divided by total production.

(3)	Includes common stock dividends and share repurchases.

Our 2013 net loss resulted from noncash asset impairments, which reduced our earnings by $2.0 billion ($1.4 billion after tax). Excluding the asset impairments and other items typically excluded by securities analysts, our adjusted earnings were $1.7 billion, or $4.26 per diluted share. This compares to adjusted earnings of $1.3 billion, or $3.22 per diluted share in 2012.

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Our 2013 adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to 2012. The improved 2013 results were driven primarily by increases in gas prices, oil volumes and oil realizations. These factors also contributed to higher adjusted operating cash flow, which combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.

Business and Industry Outlook

North American crude oil and natural gas prices have historically been volatile based on supply and demand dynamics and we expect this volatility to continue into 2014. Although natural gas prices improved in 2013 compared to 2012, natural gas continues to be challenged due to an imbalance between supply and demand across North America. However, arctic air movements across North America during the early weeks of 2014 have caused natural gas demand to surge. As storage inventories have significantly declined in response to the recent weather conditions, natural gas prices have surpassed $5 per Mcf for the first time since the summer of 2010. Further helping demand, new uses of natural gas in industrial, power and other sectors will continue to help support price dynamics. Nevertheless, we still expect natural gas prices to be range-bound as natural gas supply continues to grow, particularly in the U.S. Looking to 2014, we expect natural gas prices will remain relatively consistent or possibly increase moderately from 2013 levels.

Similar to natural gas in recent years, a surge in the supply of natural gas liquids has kept prices challenged. The majority of our natural gas is comprised of ethane, one of the most price-challenged liquids processed from the natural gas stream. We expect 2014 natural gas liquids prices will be range-bound and remain relatively flat compared to 2013.

Crude oil prices remained relatively stable throughout 2013, and oil continues to be more valuable than natural gas on a relative energy-equivalent basis. As a result, we and other producers have been focused on growing oil production. North American crude oil supply continues to increase due to the continued use of horizontal drilling technology throughout the U.S. and expansions of heavy oil production operations primarily in Canada. Global crude oil demand is expected to grow with supply in 2014. As crude oil supply grows, transportation capacity to downstream markets will be increasingly important. Bottlenecks and other transportation limitations may continue to add volatility among U.S. and Canadian grades of oil. However, we expect 2014 oil prices will remain relatively consistent with 2013.

We exited 2013 with a production profile comprised of roughly 55 percent natural gas, 25 percent oil, and 20 percent natural gas liquids. Recognizing the relative value of crude oil, we are devoting the vast majority of our 2014 capital investment toward growing our oil production, particularly the sweet grades of oil found in the U.S. To make a significant shift in our production profile, we expect to complete a $6 billion acquisition of Eagle Ford Shale assets in the first quarter of 2014 and divest non-core, dry natural gas assets throughout 2014. Once these transactions are complete, we expect oil will represent more than 30 percent of our production profile.

Further enhancing the value of our assets, we are combining substantially all of our U.S. midstream assets with Crosstex Energy, Inc.’s and Crosstex Energy, L.P.’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities. The new midstream business will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. Devon will own a 70 percent controlling interest in EnLink and an approximate 53 percent controlling interest in the Partnership.

Results of Operations

All amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.

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Oil, Gas and NGL Production

		Year Ended December 31,
		2013				Change				2012				Change				2011
Oil (MBbls/d)
Anadarko Basin			9.1				+38	%			6.6				+52	%			4.4
Barnett Shale			2.0				+22	%			1.6				-12	%			1.8
Mississippian-Woodford Trend			4.7				+625	%			0.7				N/M				—
Permian Basin			46.4				+28	%			36.3				+30	%			27.8
Rockies			7.8				+30	%			6.0				+38	%			4.3
Other			3.0				+5	%			2.8				+12	%			2.6
U.S. core and emerging properties			73.0				+35	%			54.0				+32	%			40.9
Canadian heavy oil			27.9				-3	%			28.8				-8	%			31.2
Total core and emerging properties			100.9				+22	%			82.8				+15	%			72.1
Non-core properties			15.9				+2	%			15.7				+1	%			15.6
Total			116.8				+19	%			98.5				+12	%			87.7
Bitumen (MBbls/d)
Canadian heavy oil			51.5				+8	%			47.6				+37	%			34.8
Gas (MMcf/d)
Anadarko Basin			285.8				0	%			286.3				+25	%			229.1
Barnett Shale			1,024.9				-5	%			1,074.6				+7	%			1,006.0
Mississippian-Woodford Trend			11.6				+701	%			1.5				N/M				—
Permian Basin			104.8				+24	%			84.8				+13	%			75.1
Rockies			78.0				-28	%			108.6				-23	%			140.3
Other			153.8				-12	%			175.0				-16	%			208.3
U.S. core and emerging properties			1,658.9				-4	%			1,730.8				+4	%			1,658.8
Canadian heavy oil			22.3				-18	%			27.2				-16	%			32.3
Total core and emerging properties			1,681.2				-4	%			1,758.0				+3	%			1,691.1
Non-core properties			712.2				-12	%			804.8				-12	%			918.6
Total			2,393.4				-7	%			2,562.8				-2	%			2,609.7
NGLs (MBbls/d)
Anadarko Basin			24.9				+43	%			17.3				+43	%			12.2
Barnett Shale			54.9				+17	%			46.8				+7	%			43.7
Mississippian-Woodford Trend			1.2				+770	%			0.1				N/M				—
Permian Basin			14.1				+26	%			11.2				+29	%			8.7
Rockies			0.8				+5	%			0.8				-5	%			0.8
Other			11.1				+1	%			11.0				-11	%			12.3
U.S. core and emerging properties			107.0				+23	%			87.2				+12	%			77.7
Non-core properties			18.7				-14	%			21.9				-3	%			22.6
Total			125.7				+15	%			109.1				+9	%			100.3
Combined (MBoe/d)
Anadarko Basin			81.7				+14	%			71.7				+31	%			54.7
Barnett Shale			227.7				0	%			227.5				+7	%			213.1
Mississippian-Woodford Trend			7.9				+662	%			1.0				N/M				—
Permian Basin			78.0				+27	%			61.6				+26	%			49.0
Rockies			21.5				-13	%			24.9				-13	%			28.5
Other			39.6				-8	%			43.0				-13	%			49.7
U.S. core and emerging properties			456.4				+6	%			429.7				+9	%			395.0
Canadian heavy oil			83.1				+3	%			80.9				+13	%			71.4
Total core and emerging properties			539.5				+6	%			510.6				+9	%			466.4
Non-core properties			153.4				-11	%			171.7				-10	%			191.3
Total			692.9				+2	%			682.3				+4	%			657.7

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Oil, Gas and NGL Pricing

		Year Ended December 31,
		2013 (1)				Change				2012 (1)				Change				2011 (1)
Oil (per Bbl)
U.S.		$	94.52				+7	%		$	88.68				-3	%		$	91.19
Canada		$	69.18				+1	%		$	68.29				-8	%		$	74.32
Total		$	86.02				+7	%		$	80.43				-3	%		$	83.16
Bitumen (per Bbl)
Canada		$	48.04				+1	%		$	47.57				-18	%		$	58.16
Gas (per Mcf)
U.S.		$	3.10				+33	%		$	2.32				-34	%		$	3.50
Canada		$	3.05				+23	%		$	2.49				-36	%		$	3.87
Total		$	3.09				+31	%		$	2.36				-34	%		$	3.58
NGLs (per Bbl)
U.S.		$	25.75				-10	%		$	28.49				-28	%		$	39.47
Canada		$	46.17				-5	%		$	48.63				-13	%		$	55.99
Total		$	27.33				-10	%		$	30.42				-26	%		$	41.10
Combined (per Boe)
U.S.		$	31.59				+23	%		$	25.59				-18	%		$	31.31
Canada		$	39.91				+8	%		$	37.01				-14	%		$	43.23
Total		$	33.70				+18	%		$	28.65				-17	%		$	34.64

(1)	Prices presented exclude any effects due to oil, gas and NGL derivatives.

Commodity Sales

The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales.

		Oil				Bitumen				Gas				NGLs				Total
		(In millions)
2011 sales		$	2,660			$	739			$	3,411			$	1,505			$	8,315
Change due to volumes			337				273				(52	)			137				695
Change due to prices			(98	)			(184	)			(1,148	)			(427	)			(1,857	)
2012 sales		$	2,899			$	828			$	2,211			$	1,215			$	7,153
Change due to volumes			531				65				(152	)			181				625
Change due to prices			238				9				639				(142	)			744
2013 sales		$	3,668			$	902			$	2,698			$	1,254			$	8,522

Volumes 2013 vs. 2012 – Upstream sales increased $625 million due to a 15 percent increase in our liquids production, partially offset by a 7 percent decline in our gas production. Oil production was the largest driver of the increase, accounting for 85 percent of the higher sales. Largely due to continued development of our properties in the Permian Basin, the Mississippian-Woodford Trend and the Anadarko Basin, our oil sales increased $531 million. Bitumen sales increased $65 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $181 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a 7 percent decrease in our 2013 gas production, resulting in a $152 million decline in sales.

Volumes 2012 vs. 2011 – Upstream sales increased $695 million due to a 4 percent increase in production. Oil and bitumen production were the largest drivers of the increase, accounting for nearly 90 percent of the higher sales. As a result of continued development of our liquids-rich properties in the Permian Basin, our oil

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sales increased $337 million. Bitumen sales increased $273 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $137 million as a result of continued drilling in the liquids-rich gas portions of the Barnett Shale and the Anadarko Basin. These increases were partially offset by a slight decrease in our 2012 gas production, resulting in a $52 million decline in sales.

Prices 2013 vs. 2012 – Upstream sales increased $744 million due to an 18 percent increase in our realized price without hedges. Our gas sales were the most significantly impacted with a $639 million increase in sales. The change in our gas price was largely due to higher North American regional index prices upon which our gas sales are based. Our liquid sales increased $105 million due to higher oil and bitumen sales partially offset by lower NGL sales. The largest contributors to the higher liquids prices were an increase in the average NYMEX West Texas Intermediate index price and a slightly higher bitumen realized price, partially offset by lower NGL prices at the Mont Belvieu, Texas hub.

Prices 2012 vs. 2011 – Upstream sales decreased $1.9 billion due to a 17 percent decrease in our realized price without hedges. Our gas sales were the most significantly impacted with a $1.1 billion decrease in sales. The change in our gas price was largely due to fluctuations of the North American regional index prices upon which our gas sales are based. We also experienced declines in our NGL, bitumen and oil sales due to our realized price. The largest contributors to the lower liquids prices were lower NGL prices at the Mont Belvieu, Texas hub and wider bitumen differentials.

Oil, Gas and NGL Derivatives

The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Cash settlements:
Oil derivatives		$	55			$	259			$	(26	)
Gas derivatives			139				610				416
NGL derivatives			1				1				2
Total cash settlements			195				870				392
Gains (losses) on fair value changes:
Oil derivatives			(243	)			150				185
Gas derivatives			(139	)			(330	)			305
NGL derivatives			(4	)			3				(1	)
Total gains (losses) on fair value changes			(386	)			(177	)			489
Oil, gas and NGL derivatives		$	(191	)		$	693			$	881

		Year Ended December 31, 2013
		Oil (Per Bbl)				Bitumen (Per Bbl)				Gas (Per Mcf)				NGLs (Per Bbl)				Boe (Per Boe)
Realized price without hedges		$	86.02			$	48.04			$	3.09			$	27.33			$	33.70
Cash settlements of hedges			1.30				—				0.16				0.01				0.77
Realized price, including cash settlements		$	87.32			$	48.04			$	3.25			$	27.34			$	34.47

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		Year Ended December 31, 2012
		Oil (Per Bbl)				Bitumen (Per Bbl)				Gas (Per Mcf)				NGLs (Per Bbl)				Boe (Per Boe)
Realized price without hedges		$	80.43			$	47.57			$	2.36			$	30.42			$	28.65
Cash settlements of hedges			7.19				—				0.65				0.04				3.48
Realized price, including cash settlements		$	87.62			$	47.57			$	3.01			$	30.46			$	32.13
		Year Ended December 31, 2011
		Oil (Per Bbl)				Bitumen (Per Bbl)				Gas (Per Mcf)				NGLs (Per Bbl)				Boe (Per Boe)
Realized price without hedges		$	83.16			$	58.16			$	3.58			$	41.10			$	34.64
Cash settlements of hedges			(0.81	)			—				0.44				0.07				1.63
Realized price, including cash settlements		$	82.35			$	58.16			$	4.02			$	41.17			$	36.27

Cash settlements as presented in the tables above represent realized gains or losses related to these various instruments. A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Our oil, gas and NGL derivatives include price swaps, costless collars, basis swaps and call options. To facilitate a portion of our price swaps, we sold gas and oil call options for 2014 through 2016. The call options give counterparties the right to purchase production at a predetermined price.

In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred net losses of $191 million in 2013 and generated net gains of $693 million and $881 million during 2012 and 2011, respectively.

Marketing and Midstream Revenues and Operating Costs and Expenses

		Year Ended December 31,
		2013				Change				2012				Change				2011
		($ in millions)
Revenues		$	2,066				+25	%		$	1,655				-27	%		$	2,249
Operating costs and expenses			1,553				+25	%			1,246				-27	%			1,716
Operating profit		$	513				+25	%		$	409				-23	%		$	533

2013 vs. 2012 Marketing and midstream operating profit increased $104 million, or 25 percent, from the year ended December 31, 2012 to the year ended December 31, 2013.

Our profit largely increased due to the effects of pricing and marketing activities. Our profit increased nearly $40 million due to our NGL and gas marketing. Additionally, changes in pricing led to an increase in operating profit of approximately $32 million. Higher residue natural gas prices were the primary contributor to the higher profit.

Higher gathering and processing volumes were responsible for an increase in operating profit of $21 million. Higher volumes were primarily the result of NGL production. The increase was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and downtime impacting our Bridgeport processing facility in 2012.

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Operations and maintenance expenses decreased $11 million, or 6 percent primarily due to expenditures for regulatory testing in 2012.

2012 vs. 2011 Marketing and midstream operating profit decreased $124 million, or 23 percent, from the year ended December 31, 2011 to the year ended December 31, 2012.

Our profit largely decreased due to the effects of pricing and marketing activities. Changes in pricing led to a decrease in operating profit of approximately $106 million. Lower residue natural gas and NGL prices were the primary contributor to the lower profit. Additionally, our profit decreased $13 million primarily due to lower profits on our NGL marketing.

Higher gathering, processing and transportation volumes were responsible for an increase in operating profit of $11 million. Higher volumes were primarily the result of additional throughput at Bridgeport and Cana gathering.

Operations and maintenance expenses increased $16 million, or 9 percent primarily due to expenditures for regulatory testing in 2012.

Lease Operating Expenses (“LOE”)

		Year Ended December 31,
		2013				Change				2012				Change				2011
LOE ($ in millions):
U.S.		$	1,257				+19	%		$	1,059				+14	%		$	925
Canada			1,011				-0	%			1,015				+10	%			926
Total		$	2,268				+9	%		$	2,074				+12	%		$	1,851
LOE per Boe:
U.S.		$	6.65				+15	%		$	5.79				+8	%		$	5.35
Canada		$	15.78				+4	%		$	15.18				+10	%		$	13.82
Total		$	8.97				+8	%		$	8.30				+8	%		$	7.71

2013 vs. 2012 LOE increased $0.67 per Boe largely because of our liquids production growth, particularly in the Permian Basin and the Mississippian-Woodford Trend in the U.S. These projects generally require a higher per unit cost than our gas projects, particularly because they are in the early stages of development. Additionally, we conducted a turnaround at Jackfish 2 in the third quarter of 2013, contributing to higher unit costs in 2013. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.

2012 vs. 2011 LOE increased $0.59 per Boe largely because of our oil production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. We also experienced inflationary pressures on costs in certain operating areas, which increased LOE per Boe.

General and Administrative Expenses (“G&A”)

		Year Ended December 31,
		2013				Change				2012				Change				2011
		($ in millions)
Gross G&A		$	1,128				-4	%		$	1,171				+13	%		$	1,036
Capitalized G&A			(368	)			+3	%			(359	)			+7	%			(337	)
Reimbursed G&A			(143	)			+19	%			(120	)			+5	%			(114	)
Net G&A		$	617				-11	%		$	692				+18	%		$	585
Net G&A per Boe		$	2.44				-12	%		$	2.77				+14	%		$	2.44

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2013 vs. 2012 Net G&A and net G&A per Boe decreased largely due to lower personnel expenses and office rent as a result of the Houston office consolidation in 2012 and lower costs as a result of the company-wide implementation of SAP in Q2 2012. Higher reimbursements due to increased liquids drilling activity and reimbursement rates also contributed to the decrease in net G&A and net G&A per Boe.

2012 vs. 2011 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian Basin and the Anadarko Basin.

Production and Property Taxes

		Year Ended December 31,
		2013				Change				2012				Change				2011
		($ in millions)
Production		$	275				+23	%		$	224				-10	%		$	248
Property and other			186				-2	%			190				+8	%			176
Production and property taxes		$	461				+11	%		$	414				-3	%		$	424
Percentage of oil, gas and NGL revenue:
Production			3.23	%			+3	%			3.13	%			+5	%			2.98	%
Property and other			2.18	%			-18	%			2.65	%			+25	%			2.12	%
Total			5.41	%			-6	%			5.78	%			+13	%			5.10	%

2013 vs. 2012 Production and property taxes increased primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.

2012 vs. 2011 Production and property taxes decreased primarily due to a decrease in our U.S. revenues, on which the majority of our production taxes are assessed.

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

		Year Ended December 31,
		2013				Change				2012				Change				2011
		($ in millions)
DD&A:
Oil & gas properties		$	2,465				-2	%		$	2,526				+27	%		$	1,987
Other properties			315				+11	%			285				+9	%			261
Total		$	2,780				-1	%		$	2,811				+25	%		$	2,248
DD&A per Boe:
Oil & gas properties		$	9.75				-4	%		$	10.12				+22	%		$	8.28
Other properties			1.24				+9	%			1.14				+5	%			1.09
Total		$	10.99				-2	%		$	11.26				+20	%		$	9.37

A description of how DD&A of our oil and gas properties is calculated is included in Note 1 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes.

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2013 vs. 2012 Oil and gas property DD&A decreased $61 million largely as a result of the asset impairment charges recognized in 2012 and 2013. Depreciation and amortization on our other properties increased $30 million largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.

2012 vs. 2011 Oil and gas property DD&A increased $460 million due to a 22 percent increase in the DD&A rate and $79 million due to our 4 percent increase in production. The largest contributors to the higher rate were our 2012 drilling and development activities.

Asset Impairments

		Year Ended December 31, 2013								Year Ended December 31, 2012
		Gross				Net of Taxes				Gross				Net of Taxes
		(In millions)
U.S. oil and gas assets		$	1,110			$	707			$	1,793			$	1,142
Canada oil and gas assets			843				632				163				122
Midstream assets			23				14				68				44
Total asset impairments		$	1,976			$	1,353			$	2,024			$	1,308

Oil and Gas Impairments

Under the full cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1 to the financial statements under “Item 8. Consolidated Financial Statements” of this report.

The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, natural gas and NGLs, which have reduced proved reserve values.

Midstream Impairments

Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of our midstream facilities were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.

Net Financing Costs

		Year Ended December 31,
		2013				Change				2012				Change				2011
		($ in millions)
Interest based on debt outstanding		$	466				+6	%		$	440				+6	%		$	414
Capitalized interest			(56	)			+15	%			(48	)			-33	%			(72	)
Other fees and expenses			27				+94	%			14				+33	%			10
Interest expense			437				+8	%			406				+15	%			352
Interest income			(20	)			-43	%			(36	)			+69	%			(21	)
Net financing costs		$	417				+13	%		$	370				+12	%		$	331

2013 vs. 2012 Net financing costs increased primarily due to additional debt borrowings and associated fees, partially offset by lower weighted average interest rates and higher capitalized interest. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and to provide funding for our planned Eagle Ford Shale acquisition that is expected to close in the first quarter of 2014.

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2012 vs. 2011 Net financing costs increased primarily due to additional debt borrowings and lower capitalized interest, partially offset by lower weighted average interest rates. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and divestiture proceeds.

Restructuring Costs

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Office consolidation:
Employee severance and retention		$	13			$	77			$	—
Lease obligations and other			41				3				—
Total			54				80				—
Offshore divestitures:
Employee severance		$	—			$	(3	)		$	8
Lease obligations and other			—				(3	)			(10	)
Total			—				(6	)			(2	)
Restructuring costs (1)		$	54			$	74			$	(2	)

(1)	Restructuring costs related to our discontinued operations totaled $(2) million in 2011. These costs primarily consist of employee severance and are not included in the table. There were no costs related to discontinued operations in 2013 or 2012.

Office Consolidation

In October 2012, we announced plans to consolidate our U.S. personnel into a single operations group centrally located at our corporate headquarters in Oklahoma City. As a result, we closed our office in Houston, transferred operational responsibilities for assets in south Texas, east Texas and Louisiana to Oklahoma City and incurred $134 million of restructuring costs associated with the consolidation.

Employee severance and retention – As of December 31, 2013, we had incurred $90 million of employee severance and retention costs associated with the office consolidation. This included amounts related to cash severance costs and accelerated vesting of share-based grants.

Lease obligations and other – As of December 31, 2013, we had incurred $28 million of restructuring costs related to certain office space that is subject to non-cancellable operating lease agreements and that we ceased using as a part of the office consolidation. Our estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that we may receive over the term of the leases, as well as the amount of variable operating costs that we will be required to pay under the leases.

Divestiture of Offshore Assets

In the fourth quarter of 2009, we announced plans to divest our offshore assets. As of December 31, 2012, we had divested all of our U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.

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Income Taxes

The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the United States statutory income tax rate.

		Year Ended December 31,
		2013				2012				2011
Total income tax expense (benefit) (in millions)		$	169			$	(132	)		$	2,156
United States statutory income tax rate			35	%			(35	%)			35	%
State income taxes			23	%			6	%			1	%
Taxation on Canadian operations			9	%			(6	%)			(2	%)
Repatriations			65	%			0	%			17	%
Other			(19	%)			(7	%)			(1	%)
Effective income tax rate			113	%			(42	%)			50	%

Pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of our foreign earnings had been deemed to no longer be indefinitely reinvested. As of December 31, 2012, we had recognized a $936 million deferred income tax liability related to assumed repatriations of earnings from our foreign subsidiaries, including $725 million of deferred income tax expense recognized in 2011.

In the second and fourth quarters of 2013, we repatriated to the U. S. a total of $4.3 billion of our cash held outside of the U. S. In the fourth quarter of 2013, we announced plans to divest of our Canadian non-core properties. These events resulted in incremental income tax expense of $97 million. The incremental expense included $180 million of current income tax expense offset by $83 million of deferred income tax benefit. The $83 million deferred tax benefit was comprised of $180 million of deferred tax benefits that offset the incremental current income tax expense and an additional $97 million of deferred income tax expense accrued in the fourth quarter for assumed repatriations.

In 2013, our state income tax rate is higher than 2012 and 2011 primarily due to the relatively small amount of pre-tax income, resulting from pre-tax income for the U.S. partially offset by a pre-tax loss for Canada. Also, in the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the years ended December 31, 2013 and 2012, respectively, because of the relatively small pre-tax income/loss for those periods. For 2013 “other” was comprised primarily of tax audit adjustments and a favorable tax impact due to acquisition financing.

Earnings (Loss) From Discontinued Operations

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Operating earnings		$	—			$	—			$	38
Gain (loss) on sale of oil and gas properties			—				(16	)			2,552
Earnings (loss) before income taxes			—				(16	)			2,590
Income tax expense			—				5				20
Earnings (loss) from discontinued operations		$	—			$	(21	)		$	2,570

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The earnings (loss) in each period were primarily driven by gains (losses) on the sales of our oil and gas assets in each period. In 2012 we incurred a loss of $16 million ($21 million net of taxes) for the sale of our assets in Angola. In 2011 we generated a gain of $2.5 billion ($2.5 billion net of taxes) for the sale of our assets in Brazil.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major source and use categories of our cash and cash equivalents.

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Operating cash flow – continuing operations		$	5,436			$	4,930			$	6,246
Capital expenditures			(6,758	)			(8,225	)			(7,534	)
Debt activity, net			361				1,921				4,187
Shareholder distributions			(348	)			(324	)			(2,610	)
Divestitures of property and equipment			419				1,539				3,380
Other			(24	)			81				(46	)
Net change in cash and short-term investments		$	(914	)		$	(78	)		$	3,623
Cash and short-term investments at end of period		$	6,066			$	6,980			$	7,058

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in 2013. Our operating cash flow increased 10 percent during 2013 primarily due to higher commodity prices and production growth, partially offset by higher expenses. Our operating cash flow decreased 21 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth and higher cash settlements from our commodity derivatives.

During 2013 our operating cash flow funded approximately 80 percent of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances, short-term debt and divestiture proceeds to fund the remainder of our cash-based capital expenditures.

Capital Expenditures

		Year Ended December 31,
		2013				2012				2011
		(In millions)
Development		$	4,754			$	5,183			$	5,269
Exploration			602				541				378
Acquisition			256				1,329				901
Subtotal			5,612				7,053				6,548
Capitalized G&A and interest			354				343				332
Total oil and gas			5,966				7,396				6,880
Midstream			699				504				333
Corporate and other			93				325				321
Total capital expenditures		$	6,758			$	8,225			$	7,534

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Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $6.0 billion, $7.4 billion and $6.9 billion in 2013, 2012 and 2011, respectively. The 20 percent decline in exploration, development and acquisition capital spending in 2013 was primarily due to a decline in new venture acreage acquisitions and utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements. The higher exploration and development capital spending in 2012 and 2011 was primarily due to new venture acreage acquisitions and increased drilling and development. With rising oil prices and proceeds from our offshore divestitures, we increased our onshore North American acreage positions and associated exploration and development activities to drive near-term growth of our oil production.

Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by oil and gas drilling activities. The higher 2013 midstream expenditures primarily relate to expansions of our plants serving the Barnett Shale and Cana-Woodford Shale and our Access Pipeline transporting heavy oil in Canada.

Capital expenditures related to other activities decreased in 2013. This decrease is largely driven by the construction of our new headquarters in Oklahoma City, which was completed in 2012.

Debt Activity, Net

During 2013, we increased our debt borrowings by $361 million as a result of issuing $2.25 billion of debt related to the planned Eagle Ford Shale acquisition, which is expected to close in the first quarter of 2014, and repaying approximately $1.9 billion of outstanding short-term debt.

In December 2013, to provide funding for our planned Eagle Ford Shale acquisition, we issued $2.25 billion aggregate principal amount of fixed and floating rate senior notes resulting in cash proceeds of approximately $2.2 billion, net of discounts and issuance costs.

During 2012, we increased our debt borrowings by $1.9 billion as a result of issuing $2.5 billion of long-term debt and repaying approximately $0.6 billion of outstanding short-term debt. The additional borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.

During 2011, we increased our commercial paper borrowings by $3.7 billion and received $0.5 billion from new debt issuances, net of debt maturities. Proceeds were primarily used to fund capital expenditures and common stock repurchases in excess of operating cash flow.

Shareholder Distributions

The following table summarizes our share repurchases and our common stock dividends (amounts and shares in millions).

		2013												2012												2011
		Amount				Shares				Per Share				Amount				Shares				Per Share				Amount				Shares				Per Share
Repurchases			N/A				N/A				N/A				N/A				N/A				N/A			$	2,332				31.3			$	74.54
Dividends		$	348				N/A			$	0.86			$	324				N/A			$	0.80			$	278				N/A			$	0.67

In connection with our offshore divestitures, we conducted a $3.5 billion share repurchase program that we completed in the fourth quarter of 2011. Under the program, we repurchased 49.2 million shares, representing 11 percent of our outstanding shares, at an average price of $71.18 per share.

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Divestitures of Property and Equipment

In 2013, we sold our Thunder Creek operations in Wyoming for approximately $148 million and our Bear Paw Basin assets in Havre, Montana for approximately $73 million. We also sold other minor oil and gas assets.

During 2012, we closed joint venture transactions with Sinopec and Sumitomo. Sinopec paid approximately $900 million in cash and received a 33.3 percent interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays. Sumitomo paid approximately $400 million and received a 30 percent interest in the Cline and Midland-Wolfcamp Shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays.

Also in 2012, we sold our West Johnson County Plant and gathering system in north Texas for approximately $90 million and divested our Angola operations for approximately $71 million.

In 2011, our divestitures primarily related to the divestitures of our offshore assets.

Liquidity

Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section, including our planned $6 billion acquisition of Eagle Ford Shale assets from GeoSouthern.

Operating Cash Flow and Cash Balances

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. Due to higher commodity prices, our operating cash flow from continuing operations increased 10 percent to $5.4 billion in 2013. We expect operating cash flow to continue to be our primary source of liquidity.

Commodity Prices – Prices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control. We expect this volatility to continue throughout 2014.

To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum prices on our future production. The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2013 are presented in Note 2 to the financial statements under “Item 8. Financial Statements and Supplementary Data” of this report.

Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also generally true during periods of depressed commodity prices or reduced activity.

Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2013, we had total debt of $12.0 billion with an overall weighted average borrowing rate of 4.1 percent.

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Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. Additionally, we are exposed to the credit risk of counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings.

As recent years indicate, we have a history of investing more than 100 percent of our operating cash flow into capital development activities to grow our company and maximize value for our shareholders. Therefore, negative movements in any of the variables discussed above would not only impact our operating cash flow, but also would likely impact the amount of capital investment we could or would make.

At the end of 2013, we held approximately $6.1 billion of cash. Included in this total was $1.8 billion of cash held by our foreign subsidiaries. If we were to repatriate a portion or all of the cash held by our foreign subsidiaries, we would recognize and pay current income taxes in accordance with current U. S. tax law. The payment of such additional income tax would materially decrease the amount of cash and short-term investments ultimately available to fund our business.

Credit Availability

We have a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that matures on October 24, 2018. Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate. As of December 31, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured Senior Credit Facility, net of letters of credit outstanding.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65 percent. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial write-downs, such as full cost ceiling impairments. As of December 31, 2013, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2013, as calculated pursuant to the terms of the agreement, was 25.7 percent.

Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.

We also have access to $3.0 billion of short-term credit under our commercial paper program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally based on a standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found in the commercial paper market. As of December 31, 2013, we had $1.3 billion of borrowings under our commercial paper program.

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Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Our current debt ratings are BBB with a stable outlook by Fitch, BBB+ with a negative outlook by Standard & Poor’s, and Baa1 with a review for downgrade by Moody’s.

There are no “rating triggers” in any of our debt contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 112.5 basis points to a new rate of LIBOR plus 125 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future.

Capital Expenditures

Excluding our planned $6 billion Eagle Ford Shale acquisition, our 2014 capital expenditures are expected to range from $6.4 billion to $6.9 billion, including $5.4 billion to $5.8 billion for our oil and gas operations, which include capitalized G&A and interest. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from our current estimates, we could choose to defer a portion of these planned 2014 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2014 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2014, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2014 capital expenditures.

Additionally, our financial and operational flexibility has been further enhanced by the joint venture transactions that we entered into in 2012 with Sinopec and Sumitomo. Pursuant to the joint venture agreements, Sinopec and Sumitomo are subject to drilling carries with remaining commitments that totaled $1.4 billion at the end of 2013. These drilling carries will fund 70 percent of our capital requirements related to joint venture properties, which results in our partners paying approximately 80 percent of the overall development costs during the carry period. This is allowing us to accelerate the de-risking and commercialization of the joint venture properties without diverting capital from our core development projects. We expect the remaining carries will be realized by the end of 2015.

Acquisitions and Divestitures

GeoSouthern Acquisition – On November 20, 2013, we entered into an agreement with GeoSouthern Intermediate Holdings, LLC, to acquire certain oil and gas properties, leasehold mineral interests and related assets located in the Eagle Ford Shale in south Texas for $6 billion in cash. The transaction is expected to close in the first quarter of 2014.

To provide funding for the Eagle Ford Shale acquisition, we issued $2.25 billion of senior notes in December 2013. The floating rate senior notes due in 2015 bear interest at a rate equal to three-month LIBOR plus 0.45%, which rate will be reset quarterly. The floating rate senior notes due in 2016 bear interest at a rate equal to three-month LIBOR plus 0.54%, which rate will be reset quarterly. We also entered into a term loan agreement in December 2013 with a group of major financial institutions pursuant to which we may draw up to $2.0 billion to finance, in part, the Eagle Ford Shale acquisition and to pay transaction costs. Half of any loans under the term loan agreement will have a maturity of three years and the other half will have a maturity of five years (the 5-Year Loans). The 5-Year Loans will provide for the partial amortization of principal during the last

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two years that they are outstanding. Loans borrowed under the term loan agreement may, at our election, bear interest at various fixed rate options for periods up to six months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate.

In the event that the Eagle Ford Shale acquisition is not completed on or prior to June 30, 2014, we will be required to redeem each series of new senior notes at 101% of the $2.25 billion aggregate principal amount, plus accrued and unpaid interest.

Crosstex Merger – On October 21, 2013, Devon, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively “Crosstex”) announced plans to combine substantially all of Devon’s U.S. midstream assets with Crosstex’s assets to form a new midstream business. The new business will consist of EnLink Midstream Partners, L.P. (the “Partnership”) and EnLink Midstream, LLC (“EnLink”), a master limited partnership and a general partner entity, which will both be publicly traded entities.

In exchange for a controlling interest in both EnLink and the Partnership, Devon will contribute its equity interest in a newly formed Devon subsidiary (“EnLink Holdings”) and $100 million in cash. EnLink Holdings will own Devon’s midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devon’s economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink will each own 50% of EnLink Holdings. The completion of these transactions is subject to Crosstex Energy, Inc. shareholder approval. Devon expects Crosstex Energy, Inc. shareholders will approve the transaction, allowing Devon and Crosstex to complete the transaction near the end of the first quarter of 2014.

Upon closing of the transactions, the pro forma ownership of EnLink will be approximately:

	•		70% – Devon Energy Corporation

	•		30% – Current Crosstex Energy, Inc. public stockholders

Upon closing of the transactions, the pro forma ownership of the Partnership will be approximately:

	•		53% – Devon Energy Corporation

	•		40% – Current Crosstex Energy, L.P. public unitholders

	•		7% – the General Partner

Asset Divestitures – In conjunction with the announcement of the Eagle Ford Shale acquisition, we also announced plans to monetize certain non-core assets located throughout Canada and the U. S. The divestitures will likely occur in a number of separate transactions, but we expect to complete the majority of the divestitures by the end of 2014.

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Contractual Obligations

A summary of our contractual obligations as of December 31, 2013, is provided in the following table.

		Payments Due by Period
		Total				Less Than 1 Year				1-3 Years				3-5 Years				More Than 5 Years
		(In millions)
Debt (1)		$	12,042			$	4,067			$	500			$	875			$	6,600
Interest expense (2)			7,328				472				914				845				5,097
Purchase obligations (3)			6,425				852				1,819				1,756				1,998
Operational agreements (4)			3,449				519				876				723				1,331
Asset retirement obligations (5)			2,228				88				146				141				1,853
Drilling and facility obligations (6)			366				341				25				—				—
Lease obligations (7)			285				41				72				61				111
Other (8)			446				272				78				44				52
Total		$	32,569			$	6,652			$	4,430			$	4,445			$	17,042

(1)	Debt amounts represent scheduled maturities of our debt obligations at December 31, 2013, excluding $20 million of net discounts included in the carrying value of debt. Included in current debt is the $2.25 billion senior notes related to the GeoSouthern acquisition that will be reclassified to long-term once the transaction closes in the first quarter of 2014.

(2)	Interest expense represents the scheduled cash payments on long-term, fixed-rate debt and an estimate of our floating-rate debt.

(3)

Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.

(4)	Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets.

(5)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2013 balance sheet.

(6)	Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction.

(7)	Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations.

(8)	These amounts include $243 million related to uncertain tax positions.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.

Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the

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United States of America requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. We consider the following to be our most critical accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

Full Cost Method of Accounting and Proved Reserves

Our estimates of proved reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates. We then subject certain of our reserve estimates to audits performed by outside petroleum consultants. In 2013, 91 percent of our reserves were subjected to such audits.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less than two percent of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.

While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. Applicable rules require future net revenues to be calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to the end of each quarterly period. Such rules also dictate that a 10 percent discount factor be used. Therefore, the discounted future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs or our enterprise risk.

Because the ceiling calculation dictates the use of prices that are not representative of future prices and requires a 10 percent discount factor, the resulting value is not indicative of the true fair value of the reserves. Oil and gas prices have historically been cyclical and, for any particular 12-month period, can be either higher or lower than our long-term price forecast, which is a more appropriate input for estimating fair value. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves, should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Because of the volatile nature of oil and gas prices, it is not possible to predict the timing or magnitude of full cost write-downs. In addition, due to the inter-relationship of the various judgments made to estimate proved reserves, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates. However, decreases in estimates of proved reserves would generally increase our depletion rate and, thus, our depletion expense. Decreases in our proved reserves may also increase the likelihood of recognizing a full cost ceiling write-down.

Derivative Financial Instruments

We periodically enter into derivative financial instruments with respect to a portion of our oil, gas and NGL production to hedge future prices received. Our commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.

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The estimates of the fair values of our derivative instruments require substantial judgment. We estimate the fair values of our commodity derivative financial instruments primarily by using internal discounted cash flow calculations. The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted primarily using United States Treasury bill rates. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward prices and regional price differentials.

We periodically enter into interest rate swaps to manage our exposure to interest rate volatility. Under the terms of our interest rate swaps, we generally receive a fixed rate and pay a variable rate on a total notional amount. As of December 31, 2013 we had no outstanding interest rate swaps.

We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest rate yields. The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by third parties. The resulting estimated future cash inflows or outflows over the lives of the contracts are discounted using the LIBOR and money market futures rates. These yield and discounting variables are sensitive to the period of the contract and market volatility as well as changes in forward interest rate yields.

We periodically enter into foreign exchange forward contracts to manage our exposure to fluctuations in exchange rates. Under the terms of our foreign exchange forward contracts, we generally receive U.S. dollars and pay Canadian dollars based on a total notional amount.

We estimate the fair values of our foreign exchange forward contracts primarily by using internal discounted cash flow calculations based upon forward exchange rates. The most significant variable to our cash flow calculations is our observation of forward foreign exchange rates. The resulting future cash inflows or outflows at maturity of the contracts are discounted using Treasury rates. These discounting variables are sensitive to the period of the contract and market volatility.

We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties.

Counterparty credit risk has not had a significant effect on our cash flow calculations and derivative valuations. This is primarily the result of two factors. First, we have mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our commodity derivative contracts are held with fourteen separate counterparties, and our foreign exchange forward contracts are held with four separate counterparties. Second, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below certain credit rating levels. The mark-to-market exposure threshold for collateral posting decreases as the debt rating falls further below such credit levels.

Because we have chosen not to qualify our derivatives for hedge accounting treatment, changes in the fair values of derivatives can have a significant impact on our reported results of operations. Generally, changes in derivative fair values will not impact our liquidity or capital resources.

Settlements of derivative instruments, regardless of whether they qualify for hedge accounting, do have an impact on our liquidity and results of operations. Generally, if actual market prices are higher than the price of the derivative instruments, our net earnings and cash flow from operations will be lower relative to the results that would have occurred absent these instruments. The opposite is also true. Additional information regarding

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the effects that changes in market prices can have on our derivative financial instruments, net earnings and cash flow from operations is included in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.

Goodwill

The annual impairment test, which we conduct as of October 31 each year, includes an assessment of qualitative factors and requires us to estimate the fair values of our own assets and liabilities. Because quoted market prices are not available for our reporting units, we must estimate the fair values to conduct the goodwill impairment test. The most significant judgments involved in estimating the fair values of our reporting units relate to the valuation of our property and equipment. We develop estimated fair values of our property and equipment by performing various quantitative analyses using information related to comparable companies, comparable transactions and premiums paid.

In our comparable companies analysis, we review the stock market trading multiples for selected publicly traded independent exploration and production companies with financial and operating characteristics that are comparable to our respective reporting units. Such characteristics are market capitalization, location of proved reserves and the characterization of the operations. In our comparable transactions analysis, we review certain acquisition multiples for selected independent exploration and production company transactions and oil and gas asset packages announced recently. In our premiums paid analysis, we use a sample of selected transactions of all publicly traded companies announced recently. We then review the premiums paid to the price of the target one day and one month prior to the announcement of the transaction. We use this information to determine the median premiums paid.

We then use the comparable company multiples, comparable transaction multiples, transaction premiums and other data to develop valuation estimates of our property and equipment. We also use market and other data to develop valuation estimates of the other assets and liabilities included in our reporting units. At October 31, 2013, the date of our last impairment test, the fair values of our U.S. and Canadian reporting units exceeded their related carrying values. The fair value of our U.S. reporting unit substantially exceeded its carrying value. However, the fair value of our Canadian reporting is not substantially in excess of its carrying value. As of October 31, 2013, the fair value of our Canadian reporting unit derived by the average of our three valuation methods (comparable company multiples, comparable transaction multiples, and transaction premiums) exceeded its carrying value by approximately 11 percent. As of December 31, 2013, we had $2.8 billion of goodwill allocated to the Canadian reporting unit.

Significant decreases to our stock price, decreases in commodity prices, negative deviations from projected Canadian reporting unit earnings or unfavorable changes in reserves could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.

Due to the inter-relationship of the various estimates involved in assessing goodwill for impairment, it is impractical to provide quantitative analyses of the effects of potential changes in these estimates, other than to note the historical average changes in our reserve estimates.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized.

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The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.

We also assess factors relative to whether our foreign earnings are considered indefinitely reinvested. These factors include forecasted and actual results for both our U.S. and Canadian operations, borrowing conditions in the U.S., and existing United States income tax laws, particularly the laws pertaining to the deductibility of intangible drilling costs and repatriations of foreign earnings. Changes in any of these factors could require recognition of additional deferred, or even current, U.S. income tax expense. We accrue deferred U.S. income tax expense on our foreign earnings when the factors indicate that these earnings are no longer considered indefinitely reinvested.

For our foreign earnings deemed indefinitely reinvested, we do not calculate a hypothetical deferred tax liability on these earnings. Calculating a hypothetical tax on these accumulated earnings is much different from the calculation of the deferred tax liability on our earnings deemed not indefinitely reinvested. A hypothetical tax calculation on the indefinitely reinvested earnings would require the following additional activities:

	•		Separate analysis of a diverse chain of foreign entities;

	•		Relying on tax rates on a future remittance that could vary significantly depending on alternative approaches available to repatriate the earnings;

	•		Determining the nature of a yet-to-be-determined future remittance, such as whether the distribution would be a non-taxable return of capital or a distribution of taxable earnings, and calculation of associated withholding taxes, which would vary significantly depending on the circumstances at the deemed time of remittance; and

	•		Further analysis of a variety of other inputs such as the earnings, profits, United States/foreign country tax treaty provisions and the related foreign taxes paid by our foreign subsidiaries, whose earnings are deemed permanently reinvested, over a lengthy history of operations.

Because of the administrative burden required to perform these additional activities, it is impracticable to calculate a hypothetical tax on the foreign earnings associated with this separate and more complicated chain of companies.

Non-GAAP Measures

We make reference to “adjusted earnings” and “adjusted earnings per share” in “Overview of 2013 Results” in this Item 7. that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings, as well as the per share amount, represent net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring while comparing on an annual basis. In the below table, restructuring costs were incurred in each of the three year periods, however, these costs relate to different restructuring programs. Amounts excluded for 2013 and a portion of 2012 relate to our office consolidation and amounts excluded for the remaining portion of 2012 and 2011 relate to our offshore divestiture program. For more information on our restructuring programs see Note 6 to the financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.

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Below are reconciliations of our adjusted earnings and earnings per share to their comparable GAAP measures. The reconciliations exclude amounts related to our discontinued operations.

		Year Ended December 31,
		2013				2012				2011
		(In millions, except per share amounts)
Net earnings (loss) (GAAP)		$	(20	)		$	(185	)		$	2,134
Adjustments (net of taxes):
Asset impairments			1,353				1,308				—
Derivatives and other financial instruments			131				(425	)			(546	)
Cash settlements on derivatives and financial instruments			139				558				308
U.S. income taxes on foreign earnings			97				—				744
Restructuring costs			34				49				(2	)
Insurance proceeds			—				—				(60	)
Adjusted earnings (Non-GAAP)		$	1,734			$	1,305			$	2,578
Earnings (loss) per share (GAAP)		$	(0.06	)		$	(0.47	)		$	5.10
Adjustments (net of taxes):
Asset impairments			3.35				3.23				—
Derivatives and other financial instruments			0.31				(1.04	)			(1.33	)
Cash settlements on derivatives and financial instruments			0.34				1.37				0.76
U.S. income taxes on foreign earnings			0.24				—				1.78
Restructuring costs			0.08				0.13				—
Insurance proceeds			—				—				(0.14	)
Adjusted earnings per share (Non-GAAP)		$	4.26			$	3.22			$	6.17