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

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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 2015 Results

By executing on our strategy outlined in “Items 1 and 2. Business and Properties” of this report, we strive to optimize value for our shareholders by growing cash flow, earnings, production and reserves, all on a per debt-adjusted share basis. During 2015, we had several key operating and financial achievements:

	•		Delivered record crude oil and bitumen production, representing 41% of our total production

	•		Grew U.S. oil production 28% compared to 2014

	•		Achieved top-quartile well results in the Delaware Basin of southeast New Mexico

	•		Exceeded 35 MBbls per day nameplate capacity at Jackfish 3

	•		Expanded and improved our positions in the STACK and Powder River Basin areas with two separate acquisitions completed for approximately $2 billion of cash and common equity in late 2015 and early 2016

	•		Sold EnLink units and dropped our interest in VEX to EnLink, generating $821 million in total cash inflows to Devon

	•		Realized $2.4 billion in cash settlements on our commodity hedge positions

	•		Reduced LOE $228 million, or 10%, primarily through cost reduction initiatives

	•		Exited 2015 with $4.7 billion of liquidity consisting of $2.3 billion of cash and $2.4 billion of capacity on our Senior Credit Facility. We have managed our debt maturity schedule to provide maximum flexibility with near-term liquidity; we have no major long-term debt maturities until December 2018.


		In spite of these and other operating achievements, weak commodity prices made 2015 a challenging year for the upstream energy sector, including us. As presented in the graph at left, the significant decline in crude oil prices that began in the third quarter of 2014 continued throughout 2015 and weakened further during the first two months of 2016. The 2015 WTI crude oil index was approximately 50% lower than the 2014 average. The downward pressure on oil prices has largely resulted from increased global supply, from both OPEC and non-OPEC countries, and a global economic slowdown that has decreased demand for oil. Similarly, the Henry Hub natural gas and OPIS Mont Belvieu, Texas indices decreased significantly since the end of 2014 as a result of an imbalance between supply and demand across North America.

As a result of these large commodity price declines and in spite of our operating achievements, we recognized $21 billion of noncash asset impairments throughout 2015 that have negatively impacted our financial earnings and retained earnings. Additionally, our core earnings, core earnings per share and operating cash flow for 2015 decreased significantly compared to 2014. Key measures of our financial performance in 2015 are summarized in the following table:


	Year Ended December 31,
	2015			Change			2014		Change			2013
	(Millions, except per share and per Boe amounts)
Net earnings (loss) attributable to Devon	$	(14,454	)		N/M		$	1,607		N/M		$	(20	)
Core earnings attributable to Devon (1)	$	1,044			-48	%	$	2,017		+16	%	$	1,734
Earnings (loss) per share attributable to Devon	$	(35.55	)		N/M		$	3.91		N/M		$	(0.06	)
Core earnings per share attributable to Devon (1)	$	2.52			-49	%	$	4.91		+15	%	$	4.26
Core production (MBoe/d) (2)		560			+15	%		489		+16	%		423
Total production (MBoe/d)		680			+1	%		673		-3	%		693
Realized price per Boe (3)	$	21.68			-46	%	$	40.33		+20	%	$	33.70
Operating cash flow	$	5,383			-10	%	$	5,981		+10	%	$	5,436
Capitalized costs, including acquisitions	$	6,233			-54	%	$	13,559		+104	%	$	6,643
Shareholder and noncontrolling interests distributions	$	650			+5	%	$	621		+78	%	$	348
Reserves (MMBoe)		2,182			-21	%		2,754		-7	%		2,963

(1)	Core earnings and core earnings per share attributable to Devon are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”). For a description of core earnings and core earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.

(2)	Core production is comprised of production in our key operating areas as outlined and discussed in “Items 1 and 2. Business and Properties” of this report.

(3)	Excludes any impact of oil, gas and NGL derivatives.

Business and Industry Outlook

Market prices for crude oil and natural gas are inherently volatile. Therefore, we cannot predict with certainty the future prices for the commodities we produce and sell. However, current market fundamentals indicate prices for crude oil and natural gas will continue to be depressed for much of 2016. Although changes in OPEC production strategies, macro-economic forecasts, geopolitical risks or other factors could impact current forecasts, we anticipate weak oil and natural gas prices throughout the majority of 2016.

In 2015, Devon marked its 44th anniversary in the oil and gas business and its 27th year as a public company. As an established company with a strong leadership team, we have experience operating in periods of weak commodity prices. With our focused strategy and portfolio of quality assets, we are prepared to successfully navigate the current pricing challenges and ensure our long-term financial strength.

Specifically, after completing the STACK acquisition, we began 2016 with approximately $3.9 billion of liquidity, consisting of cash and borrowing capacity under our credit facility. We expect to bolster this liquidity in 2016 by monetizing our interest in Access Pipeline and other non-core upstream assets for targeted total proceeds of $2 billion to $3 billion.

While we will continue to operate and develop our premier portfolio of assets, we are committed to protecting our balance sheet and managing our capital programs to be within our cash inflows, including Access Pipeline proceeds. As a result, we are significantly reducing our capital investment in response to lower commodity prices. We plan to invest $900 million to $1.1 billion in our upstream programs, a decrease of roughly 75% compared to our 2015 capital.

We are also committed to reducing our G&A and field-level operating costs commensurate with our reduced, but focused, activity level. In the first quarter of 2016, we announced plans to significantly reduce our

workforce and other G&A costs to better align with the activity level of our core business in the current commodity price environment. The reductions are expected to decrease gross G&A costs by approximately $400 million to $500 million on an annualized basis, excluding associated employee severance and other restructuring costs. Following a number of cost-reduction initiatives culminating with our February 2016 workforce reduction, we are expecting a $700 million to $900 million reduction in operating and G&A costs on an annualized basis.

We estimate we will incur approximately $225 million to $275 million of restructuring costs as a result of the workforce reduction. We expect to recognize the majority of these restructuring costs in the first quarter of 2016 and will recognize the remaining costs throughout 2016 until our planned divestiture transactions have closed and further workforce reductions occur.

Also, in February 2016, we reduced our quarterly common stock dividend 75% to $0.06 per share.

Results of Operations

Oil, Gas and NGL Production


	Year Ended December 31,
	2015		Change			2014		Change			2013
Oil (MBbls/d)
Delaware Basin		39		+48	%		26		+33	%		20
STACK		6		+6	%		6		+23	%		5
Eagle Ford		66		+66	%		39		N/M			—
Rockies Oil		15		+39	%		10		-1	%		11
Heavy Oil		27		+3	%		26		-7	%		28
Barnett Shale		1		-38	%		2		-2	%		2

Core assets		154		+42	%		109		+66	%		66
Other (1)		37		-25	%		49		-5	%		51

Total		191		+20	%		158		+36	%		117

Bitumen (MBbls/d)
Heavy Oil		84		+51	%		56		+8	%		51
Gas (MMcf/d)
Delaware Basin		73		+9	%		67		+16	%		57
STACK		226		-3	%		234		+14	%		205
Eagle Ford		148		+70	%		87		N/M			—
Rockies Oil		40		-17	%		47		-22	%		61
Heavy Oil		22		-5	%		23		-19	%		28
Barnett Shale		797		-12	%		909		-11	%		1,025

Core assets		1,306		-4	%		1,367		-1	%		1,376
Other (1)		304		-45	%		553		-46	%		1,017

Total		1,610		-16	%		1,920		-20	%		2,393

NGLs (MBbls/d)
Delaware Basin		9		+24	%		8		+24	%		6
STACK		21		-8	%		22		+33	%		17
Eagle Ford		25		+115	%		11		N/M			—
Rockies Oil		1		+33	%		1		+27	%		1
Barnett Shale		48		-12	%		55		-1	%		55

Core assets		104		+7	%		97		+23	%		79
Other (1)		32		-25	%		42		-11	%		47

Total		136		-2	%		139		+10	%		126

Combined (MBoe/d)
Delaware Basin		61		+35	%		45		+27	%		36
STACK		64		-4	%		67		+21	%		56
Eagle Ford		115		+75	%		65		N/M			—
Rockies Oil		23		+29	%		18		-6	%		19
Heavy Oil		115		+34	%		86		+2	%		85
Barnett Shale		182		-13	%		208		-9	%		228

Core assets		560		+14	%		489		+15	%		424
Other (1)		120		-35	%		184		-32	%		269

Total		680		+1	%		673		-3	%		693

(1)	Other assets are located primarily in the Midland Basin, east Texas, Granite Wash and Mississippian-Lime areas. Substantially all of these properties have been identified for divestiture in 2016.

Oil, Gas and NGL Pricing


	Year Ended December 31,
	2015 (1)		Change			2014 (1)		Change			2013 (1)
Oil (per Bbl)
U.S.	$	44.01		-49	%	$	85.64		-9	%	$	94.52
Canada	$	30.58		-55	%	$	68.14		-1	%	$	69.18
Total	$	42.12		-49	%	$	82.47		-4	%	$	86.02
Bitumen (per Bbl)
Canada	$	23.41		-58	%	$	55.88		+16	%	$	48.04
Gas (per Mcf)
U.S.	$	2.17		-45	%	$	3.92		+27	%	$	3.10
Canada (2)	$	0.67		-82	%	$	3.64		+19	%	$	3.05
Total	$	2.14		-45	%	$	3.90		+26	%	$	3.09
NGLs (per Bbl)
U.S.	$	9.32		-62	%	$	24.46		-5	%	$	25.75
Canada	$	—		N/M		$	50.52		+9	%	$	46.17
Total	$	9.32		-63	%	$	24.89		-9	%	$	27.33
Combined (per Boe)
U.S.	$	21.12		-44	%	$	37.96		+20	%	$	31.59
Canada	$	24.46		-54	%	$	53.11		+33	%	$	39.91
Total	$	21.68		-46	%	$	40.33		+20	%	$	33.70

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

(2)

The reported Canadian gas volumes include 12, 21 and 25 MMcf per day for the years ended 2015, 2014 and 2013, respectively, that are produced from certain of our leases and then transported to our Jackfish operations where the gas is used as fuel. However, the revenues and expenses related to this consumed gas are eliminated in our consolidated financial results. With the sale of the vast majority of the Canadian gas business in the second quarter of 2014, the eliminated gas revenues subsequently impacted our gas price more significantly.

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
	(Millions)
2013 sales	$	3,668		$	902		$	2,698		$	1,254		$	8,522
Change due to volumes		1,311			76			(533	)		131			985
Change due to prices		(206	)		160			572			(123	)		403

2014 sales	$	4,773		$	1,138		$	2,737		$	1,262		$	9,910
Change due to volumes		976			584			(443	)		(23	)		1,094
Change due to prices		(2,813	)		(1,000	)		(1,034	)		(775	)		(5,622	)

2015 sales	$	2,936		$	722		$	1,260		$	464		$	5,382

Volumes 2015 vs. 2014 Oil, gas and NGL sales increased due to volumes in 2015 because of strong production growth from our U.S. oil properties. The growth was primarily driven by the continued development of our Eagle Ford, Delaware Basin and Rockies Oil properties. Additionally, our bitumen production increased primarily due to Jackfish 3 coming on-line late in the third quarter of 2014 and reaching nameplate capacity in the third quarter of 2015. Lower royalties resulting from the significant price decrease also increased our heavy

oil production. The increases were partially offset by a decrease in our gas production, which resulted primarily from asset divestitures in 2014 and natural reservoir declines.

Volumes 2014 vs. 2013 Oil, gas and NGL sales increased due to volumes primarily because of a 66% increase in our core assets oil production. Such growth resulted from our Eagle Ford properties and the continued development of our properties in the Delaware Basin. In addition, we continued to grow our NGL production from the Delaware Basin and STACK, which resulted in $131 million of additional sales. Bitumen sales increased due to development of our Jackfish thermal heavy oil projects in Canada, including Jackfish 3 which had first sales in 2014. These increases were partially offset by a 20% decrease in our 2014 gas production, which was impacted by our asset divestitures and natural declines.

Prices 2015 vs. 2014 Oil, gas and NGL sales decreased in 2015 as a result of significantly lower prices for all commodities. The decrease in oil and bitumen sales primarily resulted from significantly lower average WTI crude oil index prices, which were approximately 50% lower in 2015 as compared to 2014. The decreases in gas and NGL sales were driven by lower North American regional index prices upon which our gas sales are based and lower NGL prices at the Mont Belvieu, Texas hub.

Prices 2014 vs. 2013 Oil, gas and NGL sales increased primarily because of a 20% increase in our realized prices without hedges. Our gas sales were the most significantly impacted. The change in our realized gas price was largely due to higher North American regional index prices upon which our gas sales are based. Additionally, our bitumen sales increased as a result of a 16% increase in our realized price, as a result of tighter bitumen and heavy oil differentials. These increases were partially offset by lower oil and NGL realized prices resulting from lower WTI crude oil index prices and lower NGL prices at the Mont Belvieu, Texas hub.

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,
	2015			2014			2013
	(Millions)
Cash settlements:
Oil derivatives	$	2,083		$	90		$	55
Gas derivatives		333			(36	)		139
NGL derivatives		—			1			1

Total cash settlements		2,416			55			195

Gains (losses) on fair value changes:
Oil derivatives		(1,687	)		1,721			(243	)
Gas derivatives		(226	)		213			(139	)
NGL derivatives		—			—			(4	)

Total gains (losses) on fair value changes		(1,913	)		1,934			(386	)

Oil, gas and NGL derivatives	$	503		$	1,989		$	(191	)


	Year Ended December 31, 2015
	Oil (Per Bbl)		Bitumen (Per Bbl)		Gas (Per Mcf)		NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	42.12	$	23.41	$	2.14	$	9.32	$	21.68
Cash settlements of hedges		29.88		—		0.57		—		9.74

Realized price, including cash settlements	$	72.00	$	23.41	$	2.71	$	9.32	$	31.42


	Year Ended December 31, 2014
	Oil (Per Bbl)		Bitumen (Per Bbl)		Gas (Per Mcf)			NGLs (Per Bbl)		Boe (Per Boe)
Realized price without hedges	$	82.47	$	55.88	$	3.90		$	24.89	$	40.33
Cash settlements of hedges		1.56		—		(0.05	)		0.02		0.22

Realized price, including cash settlements	$	84.03	$	55.88	$	3.85		$	24.91	$	40.55


	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

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 3 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 2015 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 generated net gains in 2015 and 2014 and incurred a net loss in 2013.

Marketing and Midstream Revenues and Operating Expenses


	Year Ended December 31,
	2015			Change			2014			Change			2013
	(Millions)
Operating revenues	$	7,260			-5	%	$	7,667			+271	%	$	2,066
Product purchases		(6,028	)		-8	%		(6,540	)		+382	%		(1,356	)
Operations and maintenance expenses		(392	)		+43	%		(275	)		+40	%		(197	)

Operating profit	$	840			-1	%	$	852			+66	%	$	513


Devon profit	$	14			-84	%	$	88			-5	%	$	93
EnLink profit		826			+8	%		764			+82	%		420

Total profit	$	840			-1	%	$	852			+66	%	$	513

2015 vs. 2014 Marketing and midstream operating profit changes were largely driven by a full year of EnLink’s legacy asset operations compared to prior year and facility expansions coming online in late 2014, along with assets acquired during 2015. The change was offset by a decrease in Devon’s marketing activities due to a decrease in commodity prices.

2014 vs. 2013 Marketing and midstream operating profit largely increased as a result of higher prices and volumes, partially offset by higher operations and maintenance expenses. Of the $339 million increase, $344 million was attributed to EnLink’s operations. Higher profits from EnLink’s Texas segment, which includes the Bridgeport facility, and Louisiana segment were the largest drivers of the increase. The Louisiana segment operating profit increased because of acquisitions and completions of additional pipelines.

Devon’s marketing activities were the primary driver of the increases in both operating revenues and product purchases. The higher marketing revenues and product purchases are primarily due to commitments we entered into to secure capacity on downstream oil pipelines. Marketing activities of EnLink also contributed to these increases.

Lease Operating Expenses


	Year Ended December 31,
	2015		Change			2014		Change			2013
	(Millions, except per Boe amounts)
LOE:
U.S.	$	1,551		-0	%	$	1,559		+24	%	$	1,257
Canada		553		-28	%		773		-24	%		1,011

Total	$	2,104		-10	%	$	2,332		+3	%	$	2,268

LOE per Boe:
U.S.	$	7.52		+0	%	$	7.52		+13	%	$	6.65
Canada	$	13.18		-34	%	$	20.10		+27	%	$	15.78
Total	$	8.48		-11	%	$	9.49		+6	%	$	8.97

2015 vs. 2014 LOE per Boe decreased during 2015 primarily as a result of higher Jackfish 3 volumes, our well optimization and cost reduction initiatives, lower royalties and changes in the Canadian to U.S. foreign exchange rate. As Canadian royalties decrease, our net production volumes increase, causing improvements to our per-unit operating costs. The flat U.S. rate is primarily related to our 2014 non-core natural gas asset divestitures and our oil production growth, where projects generate higher margins but generally require a higher cost to produce per unit than our retained and divested gas projects.

2014 vs. 2013 Our absolute LOE changed largely as a result of our portfolio transformation initiatives, including our February 2014 purchase of Eagle Ford assets and our 2014 divestitures of non-core gas properties in the U.S. and Canada. Higher volumes from development of our Eagle Ford assets, as well as our Delaware Basin assets, caused U.S. LOE to increase. This increase was partially offset by the decrease resulting from the U.S. divestitures. The Canadian divestitures were the primary cause of the decrease in Canadian LOE.

Total LOE increased $0.52 per Boe primarily because of higher unit costs related to our Canadian operations. The higher Canadian unit costs largely resulted from the divestiture of the conventional natural gas assets in the second quarter of 2014 which resulted in lower total volumes while retaining the relatively higher-cost thermal heavy oil operations. Additionally, higher Jackfish royalties paid in 2014 also contributed to higher Canadian unit costs. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Delaware Basin and Mississippian-Woodford Trend, where projects generate higher revenues but generally require a higher cost to produce per unit than our gas projects. Additionally, we experienced inflationary pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.

General and Administrative Expenses


	Year Ended December 31,
	2015			Change			2014			Change			2013
	(Millions, except per Boe amounts)
Gross G&A	$	1,347			-2	%	$	1,369			+21	%	$	1,128
Capitalized G&A		(372	)		-1	%		(376	)		+2	%		(368	)
Reimbursed G&A		(120	)		-18	%		(146	)		+2	%		(143	)

Net G&A	$	855			+1	%	$	847			+37	%	$	617

Net G&A per Boe	$	3.45			+0	%	$	3.45			+41	%	$	2.44

2015 vs. 2014 Gross G&A decreased during 2015 largely because of a lower employee performance bonus pool and our cost reduction initiatives. Furthermore, $22 million in one-time costs related to the EnLink and GeoSouthern transactions contributed to higher costs in the first quarter of 2014. These decreases were offset by an increase in EnLink G&A of approximately $40 million primarily resulting from a workforce increase associated with EnLink’s 2015 acquisitions. Reimbursed G&A decreased subsequent to our 2014 asset divestitures.

2014 vs. 2013 Net G&A and net G&A per Boe increased largely due to higher employee compensation and benefits and $22 million of 2014 costs related to the EnLink and GeoSouthern transactions. The higher employee compensation and benefits costs were primarily related to share-based awards, which cause our G&A to be higher in the period in which our annual share-based grant is made. The grant related to our 2013 compensation cycle was made in the first quarter of 2014. The grant related to our 2012 compensation cycle was made in the fourth quarter of 2012. Additionally, the expansion of our workforce as a part of growing production operations at certain of our key areas also contributed to the increase.

Production and Property Taxes


	Year Ended December 31,
	2015			Change			2014			Change			2013
	(Millions)
Production	$	198			-45	%	$	360			+31	%	$	275
Property and other		190			+8	%		175			-6	%		186

Production and property taxes	$	388			-28	%	$	535			+16	%	$	461


Percentage of oil, gas and NGL sales:
Production		3.7	%		+1	%		3.6	%		+13	%		3.2	%
Property and other		3.5	%		+100	%		1.8	%		-19	%		2.2	%

Total		7.2	%		+33	%		5.4	%		-0	%		5.4	%

2015 vs. 2014 Our absolute production taxes decreased during 2015 primarily because of a decrease in our U.S. revenues, on which the majority of our production taxes are assessed. Property taxes as a percentage of oil, gas and NGL sales increased during 2015 primarily due to ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL sales.

2014 vs. 2013 Production and property taxes increased primarily as a result of an increase in our U.S. revenues.

Depreciation, Depletion and Amortization


	Year Ended December 31,
	2015		Change			2014		Change			2013
	(Millions, except per Boe amounts)
DD&A:
Oil and gas properties	$	2,580		-11	%	$	2,896		+18	%	$	2,465
Other assets		549		+30	%		423		+34	%		315

Total	$	3,129		-6	%	$	3,319		+19	%	$	2,780


DD&A per Boe:
Oil and gas properties	$	10.40		-12	%	$	11.79		+21	%	$	9.75
Other assets		2.21		+28	%		1.72		+38	%		1.24

Total	$	12.61		-7	%	$	13.51		+23	%	$	10.99

A description of how DD&A of our oil and gas properties is calculated is included in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report. Generally, when reserve volumes are revised up or down, the DD&A rate per unit of production will change inversely. However, when the depletable base changes, 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.

2015 vs. 2014 DD&A from our oil and gas properties decreased in 2015 compared to 2014 largely because of the 2014 divestitures of certain U.S. and Canadian assets and the oil and gas asset impairments recognized in 2015. Other DD&A increased primarily due to EnLink’s acquisitions in 2014 and 2015.

2014 vs. 2013 DD&A from our oil and gas properties increased in 2014 largely because of higher DD&A rates. The higher rates resulted from our oil and gas drilling and development activities and the GeoSouthern acquisition, which were partially offset by the asset impairments recognized in 2013 and the 2014 asset divestitures. Other DD&A increased primarily due to the formation of EnLink in 2014.

Asset Impairments

During 2015, 2014 and 2013, we recognized asset impairments of $20.8 billion, $2.0 billion and $2.0 billion, respectively. For discussion on asset impairments, see Note 5 in “Item 8. Financial Statements and Supplementary Data” of this report.

Restructuring Costs

During 2015, 2014 and 2013, we recognized restructuring costs of $78 million, $46 million and $54 million, respectively. For discussion of our reorganization programs and the associated restructuring costs, see Note 6 in “Item 8. Financial Statements and Supplementary Data” of this report.

Gains on Asset Sales

In conjunction with the divestiture of certain Canadian properties, we recognized gains of $1.1 billion in 2014. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Net Financing Costs


	Year Ended December 31,
	2015			Change			2014			Change			2013
	(Millions)
Interest based on debt outstanding	$	565			+6	%	$	532			+14	%	$	466
Early retirement of debt		—			N/M			48			N/M			—
Capitalized interest		(62	)		-11	%		(70	)		+26	%		(56	)
Other fees and expenses		20			-24	%		26			-1	%		27

Interest expense		523			-3	%		536			+23	%		437
Interest income		(6	)		-41	%		(10	)		-49	%		(20	)

Net financing costs	$	517			-2	%	$	526			+26	%	$	417

2015 vs. 2014 Net financing costs decreased during 2015 primarily as a result of the retirement premium and costs related to the early redemption of senior notes in 2014, which is further discussed in Note 13 in “Item 8. Financial Statements and Supplementary Data” of this report. Interest on outstanding borrowings increased during 2015 primarily due to an increase of $51 million in EnLink interest expense as a result of an increase in fixed-rate borrowings, partially offset by a $18 million decrease in Devon interest expense as a result of a decrease in its average fixed-rate borrowings.

2014 vs. 2013 Net financing costs increased primarily because of higher average borrowings resulting from the EnLink and GeoSouthern transactions and the 2014 early retirement premium and costs.

Income Taxes


	Year Ended December 31,
	2015			2014			2013
Total income tax expense (benefit) (millions)	$	(6,065	)	$	2,368		$	169

Effective income tax rate		(29	)%		58	%		113	%

For discussion on income taxes, see Note 7 in “Item 8. Financial Statements and Supplementary Data” of this report.

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.


	Devon						EnLink						Consolidated
	2015			2014			2015			2014			2015			2014			2013 (1)
	(Millions)
Operating cash flow	$	4,756		$	5,467		$	627		$	514		$	5,383		$	5,981		$	5,436
Sale of subsidiary units		654			—			—			—			654			—			—
Divestitures of property and equipment		106			5,120			1			—			107			5,120			419
Capital expenditures		(4,735	)		(6,192	)		(573	)		(796	)		(5,308	)		(6,988	)		(6,502	)
Acquisitions of property, equipment and businesses		(583	)		(6,104	)		(524	)		(358	)		(1,107	)		(6,462	)		(256	)
Short-term investment activity, net		—			—			—			—			—			—			2,343
Debt activity, net		770			(2,789	)		1,061			555			1,831			(2,234	)		361
Shareholder and noncontrolling interests distributions		(396	)		(486	)		(254	)		(135	)		(650	)		(621	)		(348	)
EnLink and General Partner distributions		268			158			(268	)		(158	)		—			—			—
EnLink dropdowns		167			—			(167	)		—			—			—			—
Stock option proceeds		4			93			—			—			4			93			3
Issuance of subsidiary units		—			—			25			410			25			410			—
Effect of exchange rate and other		(131	)		79			22			36			(109	)		115			(27	)

Net change in cash and cash equivalents	$	880		$	(4,654	)	$	(50	)	$	68		$	830		$	(4,586	)	$	1,429

Cash and cash equivalents at end of period	$	2,292		$	1,412		$	18		$	68		$	2,310		$	1,480		$	6,066

(1)	2013 amounts for EnLink consist of legacy Devon midstream assets.

Operating Cash Flow

Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2015. Our operating cash flow decreased 10% during 2015 primarily due to lower commodity prices. The effects of lower commodity prices were partially offset by the collection of $425 million of income taxes receivable in the first quarter of 2015 and $2.4 billion of cash settlements associated with our commodity derivatives during 2015.

Our operating cash flow increased 10% during 2014 primarily because of higher realized prices and liquids production growth, partially offset by higher expenses.

Excluding payments made for acquisitions, our consolidated operating cash flow funded 100% and approximately 86% of our capital expenditures during 2015 and 2014, respectively. In 2015 and 2014, leveraging our liquidity and other capital resources, we also used cash balances, short-term debt, proceeds from EnLink transactions and divestiture proceeds to fund our acquisitions, dividends and capital requirements.

Sale of Subsidiary Units

In early 2015, we conducted an underwritten secondary public offering of 26.2 million common units representing limited partner interests in EnLink, raising proceeds of $654 million, net of underwriting discount. See Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report.

Divestitures of Property and Equipment

During 2014, we completed our Canadian asset divestiture program and received proceeds of approximately $2.9 billion. Additionally, we completed the divestment of certain of our U.S. assets and received proceeds of approximately $2.2 billion.

During 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.

Capital Expenditures


	Year Ended December 31,
	2015		2014		2013
	(Millions)
Oil and gas	$	4,577	$	5,735	$	5,710
Midstream		56		348		455
Corporate and other		102		109		93

Devon capital expenditures		4,735		6,192		6,258
EnLink capital expenditures		573		796		244

Total capital expenditures	$	5,308	$	6,988	$	6,502

Devon acquisitions	$	583	$	6,104	$	256
EnLink acquisitions		524		358		—

Total acquisitions	$	1,107	$	6,462	$	256

Capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations, other corporate activities and EnLink growth and maintenance activities.

The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties. In response to lower commodity prices, Devon’s 2015 capital program was designed to be lower than 2014, particularly compared to the second half of 2014 when oil prices began to significantly decline. This change is evidenced by a 48% decrease in exploration and development costs from the fourth quarter of 2014 to the fourth quarter of 2015, as well as a 24% decrease in total capital expenditures from 2014 to 2015, excluding acquisitions. Excluding acquisitions, oil and gas capital spending was flat from 2013 to 2014, primarily due to utilization of the drilling carries in 2014 from our joint venture arrangements.

Capital expenditures for Devon’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines and are largely impacted by Devon’s oil and gas drilling activities. Our 2014 and 2013 midstream capital expenditures largely related to the expansion of our Access Pipeline in Canada. The majority of our midstream capital is incurred by EnLink. EnLink’s 2015 capital expenditures decreased compared to 2014 primarily as a result of pipeline construction and expansion projects that went into service in 2014. EnLink’s 2013 capital expenditures primarily related to expansions of plants serving the Barnett Shale and Cana-Woodford Shale.

Acquisition capital spend in 2015 primarily consisted of the Powder River Basin asset acquisition in the fourth quarter. The majority of the acquisition capital in 2014 related to the GeoSouthern acquisition in the Eagle Ford. EnLink’s acquisitions in 2015 and 2014 consisted of additional oil and gas pipeline assets, including gathering, transportation and processing facilities. For further discussion on EnLink acquisition activity, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Short-Term Investment Activity, Net

During 2013, we purchased approximately $1.1 billion of short-term investments and redeemed approximately $3.4 billion. We consider securities with original contract maturities in excess of three months but less than one year to be short-term investments.

Debt Activity, Net

During 2015, our consolidated net debt borrowings increased $1.8 billion. In June 2015, we issued $750 million of 5.0% senior notes. We used these proceeds to repay the aggregate principal amount of our floating rate senior notes upon maturity on December 15, 2015, as well as outstanding commercial paper balances. In December 2015, we issued $850 million of 5.85% senior notes to fund acquisitions announced in the fourth quarter. EnLink’s net debt borrowings increased $1.1 billion primarily from borrowings made to fund acquisitions and dropdowns.

During 2014, we decreased our net debt borrowings by $2.2 billion. The decrease was primarily related to the repayment of debt used to fund the GeoSouthern transaction. This was partially offset by $555 million of net borrowings from EnLink to fund its operations.

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 acquisition and repaying approximately $1.9 billion of outstanding short-term debt.

Shareholder and Noncontrolling Interests Distributions

The following table summarizes our common stock dividends. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. We increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.


	2015				2014				2013
	Amount		Per Share		Amount		Per Share		Amount		Per Share
	(Millions, except per share amounts)
Dividends	$	396	$	0.96	$	386	$	0.94	$	348	$	0.86

In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Furthermore, EnLink and the General Partner distributed $254 and $135 million to non-Devon unitholders during 2015 and 2014, respectively.

EnLink and General Partner Distributions

Devon received $268 million and $158 million in distributions from EnLink and the General Partner during 2015 and 2014, respectively.

EnLink Dropdowns

In the second quarter of 2015, Devon received $167 million in cash from EnLink in exchange for VEX. For further discussion, see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Stock Option Proceeds

We received $4 million, $93 million and $3 million from stock option proceeds in 2015, 2014 and 2013, respectively.

Issuance of Subsidiary Units

During 2015 and 2014, EnLink issued and sold approximately 1.3 million and 14.8 million common units through general public offerings and its “at the market” equity program, generating net proceeds of approximately $25 million and $410 million, respectively. Furthermore, in October 2015, EnLink issued approximately 2.8 million common units in a private placement transaction with the General Partner, generating approximately $50 million in proceeds.

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 a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. We estimate the combination of these sources of capital will continue to be adequate to fund future capital expenditures, debt repayments and other contractual commitments as discussed in this section.

Operating Cash Flow

Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow decreased 10% in 2015 as a result of the significant decrease in commodity prices. In spite of this decline, we expect operating cash flow to continue to be a primary source of liquidity as we adjust our capital program in response to lower commodity prices. Additionally, we anticipate utilizing divestiture proceeds and our credit availability to provide additional liquidity as needed.

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 lower prices to continue throughout 2016, and currently, our production is largely unhedged. If commodity prices remain consistent with 2015 and we are unable to obtain favorable hedge contracts for our 2016 production, our 2016 operating cash flow could materially decline from what it was in 2015.

The key terms to our oil, gas and NGL derivative financial instruments as of December 31, 2015 are presented in Note 3 in “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 decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.

Divestitures of Property and Equipment – In the fourth quarter of 2015, we announced our intention to monetize up to 80 MBoe per day of certain non-core upstream assets across our portfolio in 2016. In addition, we also intend to market our Access Pipeline in Canada. We anticipate these divestitures will generate approximately $2 billion to $3 billion of proceeds to further strengthen our financial position in 2016.

Interest Rates – Our operating cash flow can also be impacted by interest rate fluctuations. As of December 31, 2015, we had total debt of $13.1 billion with an overall weighted-average borrowing rate of 4.9%. Of the $13.1 billion of total debt, $1.4 billion is comprised of floating rate debt instruments that bear interest rates averaging 1.1%.

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% 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. In the current environment, assuming current pricing expectations, our 2016 exploration and development capital budget is expected to be approximately $900 million to $1.1 billion, or roughly 75% less than our 2015 capital program. With our 2016 capital focused primarily on oil development, we anticipate our oil production will remain relatively flat from 2015 to 2016, but our natural gas and NGL production will decline, resulting in a 6% production decline in our core assets.

At the end of 2015, we held approximately $2.3 billion of cash. Included in this total was $646 million 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 decrease the amount of cash ultimately available to fund our business.

Credit Availability

We have a $3.0 billion Senior Credit Facility. The maturity date for $30 million of the Senior Credit Facility is October 24, 2017. The maturity date for $164 million of the Senior Credit Facility is October 24, 2018. The maturity date for the remaining $2.8 billion is October 24, 2019. This credit facility supports our $3.0 billion commercial paper program. 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, 2015, there were no borrowings under the Senior Credit Facility.

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%. 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 and goodwill impairments. As of December 31, 2015, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2015, as calculated pursuant to the terms of the agreement, was 23.7%.

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.

Our Senior Credit Facility supports our $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, 2015, we had $626 million of borrowings under our commercial paper program.

EnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million revolving credit facility. As of December 31, 2015, there were $11 million in outstanding letters of credit and $414 million borrowed under the $1.5 billion credit facility and no outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors, we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which would impact the trading liquidity of such indebtedness.

Debt Ratings

Devon and EnLink are rated by the major debt ratings agencies in the U.S. However, the General Partner does not receive debt ratings. In determining those debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales, near-term and long-term growth opportunities and capital allocation challenges.

There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should debt ratings fall below a specified level. However, a ratings downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Capital Expenditures

In January 2016, Devon acquired Anadarko Basin STACK assets for approximately $1.5 billion in cash and equity, subject to certain adjustments. Including this acquisition but excluding EnLink, our 2016 capital expenditures are expected to range from $1.2 billion to $1.4 billion, including $900 million to $1.1 billion for our oil and gas capital program. 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 2016 capital expenditures until later periods or accelerate capital expenditures planned for periods beyond 2016 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2016, available cash balances and credit availability and proceeds from our divestiture program, we anticipate having adequate capital resources to fund our 2016 capital expenditures.

In connection with our acquisition of the STACK play and Powder River Basin assets, we issued 23,470,000 shares of our common stock (the “STACK Acquisition Shares”) and 6,857,488 shares of our common stock (the “PRB Acquisition Shares”), respectively. Pursuant to the terms of these acquisitions, we agreed to register for resale with the SEC the STACK Acquisition Shares and the PRB Acquisition Shares. Following such respective registrations, the STACK Acquisition Shares and the PRB Acquisition Shares can generally be freely sold in the public markets at any time on or after February 21, 2016 and March 16, 2016, respectively.

EnLink Capital Resources and Expenditures

In January 2016, EnLink acquired Tall Oak, a gathering and processing midstream company with assets in central Oklahoma, for approximately $1.5 billion in cash and equity, subject to certain adjustments.

Excluding this acquisition, EnLink’s 2016 capital budget includes approximately $445 million to $570 million of identified growth projects. EnLink’s primary capital projects for 2016 include completing the construction of the Riptide plant in Texas, acquired as part of the Coronado transaction, commencing construction on an NGL pipeline in Louisiana and development of its Tall Oak assets.

EnLink expects to fund the growth capital expenditures from the proceeds of borrowings under its bank credit facility and proceeds from other debt and equity sources. EnLink expects to fund its 2016 maintenance capital expenditures from operating cash flows. In 2016, it is possible that not all of the planned projects will be commenced or completed. EnLink’s ability to pay distributions to its unitholders, fund planned capital expenditures and make acquisitions will depend upon its future operating performance, which will be affected by prevailing economic conditions in the industry and financial, business and other factors, some of which are beyond its control.

Contractual Obligations

The following table presents a summary of our contractual obligations as of December 31, 2015.


	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
	(Millions)
Devon debt (1)	$	10,051	$	976	$	875	$	700	$	7,500
EnLink debt (2)		3,077		—		—		814		2,263
Interest expense (3)		9,804		630		1,252		1,115		6,807
Purchase obligations (4)		3,905		557		1,494		1,648		206
Operational agreements (5)		4,601		994		1,908		657		1,042
Asset retirement obligations (6)		1,414		44		104		102		1,164
Drilling and facility obligations (7)		189		69		85		7		28
Lease obligations (8)		443		70		134		110		129
Other (9)		140		2		92		39		7

Total (10)	$	33,624	$	3,342	$	5,944	$	5,192	$	19,146

(1)	Debt amounts represent scheduled maturities of Devon’s debt obligations at December 31, 2015, excluding $28 million of net discounts included in the carrying value of debt. Debt due less than one year includes $626 million of commercial paper, which can be renewed beyond one year.

(2)	Debt amounts represent scheduled maturities of EnLink’s debt obligations at December 31, 2015, excluding $13 million of net premiums included in the carrying value of debt. All of EnLink’s debt is non-recourse to Devon.

(3)	Interest expense represents the scheduled cash payments on long-term, fixed-rate debt and an estimate of our floating-rate notes. These amounts include $1.8 billion of interest expense related to EnLink.

(4)

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.

(5)

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. Operational agreements include approximately $1.7 billion of minimum volume commitments between Devon and EnLink. The initial terms of the gas volume contracts with EnLink are summarized in the following table. In addition, Devon and EnLink have a 30 MBbls/d minimum transportation volume commitment for the VEX pipeline. All contracts with EnLink expire in 2019.


Contract	Contract Terms (Years)		Minimum Gathering Volume Commitment (MMcf/d)		Minimum Processing Volume Commitment (MMcf/d)		Minimum Volume Commitment Term (Years)		Annual Rate Escalators
Bridgeport gathering and processing contract		10		850		650		5		CPI
East Johnson County gathering contract		10		125		—		5		CPI
Cana gathering and processing contract		10		330		330		5		CPI

(6)	Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2015 balance sheet.

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

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

(9)	These amounts include $133 million related to uncertain tax positions.

(10)	This table excludes approximately $1.7 billion of cash payments made on January 7, 2016 upon closing the STACK acquisition and EnLink’s acquisition of Tall Oak. The table also excludes the $500 million of future cash installment payments required to be paid by EnLink within 24 months as part of the Tall Oak acquisition.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 18 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 U.S. 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 third-party petroleum consulting firms. In 2015, 95% 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 3% 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% 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% 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 generally is not possible to predict the timing or magnitude of full cost write-downs. In addition, because of 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.

Based on prices for the last nine months of 2015 and the short-term pricing outlook for the first quarter of 2016, we expect to recognize additional U.S. and Canadian full cost impairments in the first quarter of 2016. The estimated U.S. impairment would be material to our net earnings, but we believe it will not be as large as the $3.7 billion impairment we recognized in the fourth quarter of 2015. We also expect to recognize an impairment related to our Canadian oil and gas properties that will approximate the impairment recognized in the fourth quarter of 2015. While difficult to measure, we estimate that the first quarter 2016 impairments will approximate $3 billion in the aggregate. Our full cost impairments have no impact to our cash flow or liquidity.

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. Additionally, EnLink periodically enters into derivative financial instruments with respect to its oil, gas and NGL marketing activity. These commodity derivative financial instruments include financial price swaps, basis swaps, costless price collars and call options.

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 WTI 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 U.S. 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. 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.

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 oil, gas and NGL commodity derivative contracts are held with thirteen separate counterparties, and our foreign exchange forward contracts are held with six 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.

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 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.

Business Combinations

Accounting for the acquisition of a business requires the assets and liabilities of the acquired business to be recorded at fair value. Deferred taxes are recorded for any differences between the fair value and the tax basis of the acquired assets and liabilities. Any excess of the purchase price over the fair values of the tangible and intangible net assets acquired is recorded as goodwill.

There are various assumptions we make in determining the fair values of an acquired company’s assets and liabilities. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of the oil and gas properties acquired. To determine the fair values of these properties, we prepare estimates of oil, natural gas and NGL reserves. These estimates are based on work performed by our engineers and that of outside consultants. The judgments associated with these estimated reserves are described earlier in this section in connection with the full cost ceiling calculation.

However, there are factors involved in estimating the fair values of acquired oil, natural gas and NGL properties that require more judgment than that involved in the full cost ceiling calculation. As stated above, the full cost ceiling calculation applies a historical 12-month average price to the reserves to arrive at the ceiling amount. By contrast, the fair value of reserves acquired in a business combination must be based on our estimates of future oil, natural gas and NGL prices. Our estimates of future prices are based on our own analysis of pricing trends. These estimates are based on current data obtained with regard to regional and worldwide supply and demand dynamics such as economic growth forecasts. They are also based on industry data regarding natural gas storage availability, drilling rig activity, changes in delivery capacity, trends in regional pricing differentials and other fundamental analysis. Forecasts of future prices from independent third parties are noted when we make our pricing estimates.

We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues are then discounted using a rate determined appropriate at the time of the business combination based upon our cost of capital.

We also apply these same general principles to estimate the fair value of unproved properties acquired in a business combination. These unproved properties generally represent the value of probable and possible reserves. Because of their very nature, probable and possible reserve estimates are more imprecise than those of proved reserves. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by what we consider to be an appropriate risk-weighting factor in each particular instance.

In addition, our acquisitions have involved other entities whose operations included substantial midstream activities. In these transactions, the purchase price is allocated to the fair value of midstream facilities and equipment, generally consisting of processing facilities and pipeline systems. Estimating the fair value of these assets requires certain assumptions to be made regarding future quantities of commodities estimated to be processed and transported through these facilities and pipelines, as well as estimates of future expected prices and operating and capital costs.

Goodwill

We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. While we use data as of October 31 for our test, we typically complete the test in late December or early January as the October 31 market data used in our test becomes available. We first assess the qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. If we determine that it is more likely than not that its fair value is less than its carrying amount, then the two-step goodwill impairment test is performed.

In the first step of the impairment test, the fair value of a reporting unit is compared to its carrying value. Because quoted market prices are not available for our reporting units, the fair values of the reporting units are estimated based upon several valuation analyses, including comparable companies, comparable transactions and premiums paid. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment

test is performed for purposes of measuring the impairment. In the second step, the fair value of the reporting unit is allocated to all of the assets and liabilities of the reporting unit to determine an implied goodwill value. This allocation is similar to a purchase price allocation. If the carrying amount of the reporting unit’s goodwill exceeds the implied fair value of goodwill, an impairment loss is recognized in an amount equal to that excess. The determination of fair value requires judgment and involves the use of significant estimates and assumptions about expected future cash flows derived from internal forecasts and the impact of market conditions on those assumptions. Critical assumptions primarily include revenue growth rates driven by future commodity prices and volume expectations, operating margins and capital expenditures.

For our October 31, 2015 impairment test, step one of our impairment analysis showed that the fair value of our U.S. reporting unit exceeded its carrying value.

Sustained weakness in the overall energy sector beginning in the fourth quarter of 2014 and continuing into 2015 driven by low commodity prices, together with a decline in the EnLink unit price, caused a change in circumstances warranting an interim impairment test for EnLink’s reporting units, as well as an update performed as of December 31. Based on the results of the impairment analysis, it was determined that the estimated fair value of EnLink’s Crude and Condensate, Louisiana and Texas reporting units were less than their carrying amounts, primarily due to changes in assumptions related to commodity prices and discount rates. Through the analysis, goodwill impairments of $492 million, $787 million and $49 million for EnLink’s Texas, Louisiana and Crude and Condensate reporting units, respectively, were recognized in 2015. Subsequent to the impairments, EnLink had $93 million and $704 million of goodwill allocated to the Crude and Condensate and Texas reporting units, respectively. The Louisiana reporting unit’s goodwill was entirely written off. As of December 31, 2015, the fair value of EnLink’s Texas reporting unit exceeded its carrying value by approximately 7%, and the carrying value of EnLink’s Crude and Condensate reporting unit approximated its fair value.

The impairment of goodwill has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.

Other Intangible Assets

In 2015, the assessment of customer relationships was updated due to the factors described in the aforementioned goodwill section. This assessment resulted in a $223 million impairment of other intangible assets related to EnLink’s Crude and Condensate reporting unit. Level 3 fair value measurements were utilized for the impairment analysis of definite-lived intangible assets, which included discounted cash flow estimates, consistent with those utilized in the goodwill impairment assessment.

The other intangible assets impairment has no effect on liquidity or capital resources. However, it adversely affects our results of operations in the period recognized.

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. At the end of 2015, we had deferred tax assets that largely resulted from the full cost impairments recognized in the fourth quarter of 2015. As a result of our recent cumulative losses, we recorded a 100% valuation allowance against our U.S. deferred tax assets as of December 31, 2015.

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 U.S. 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, U.S./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 impractical 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 “core earnings attributable to Devon” and “core earnings per share attributable to Devon” in “Overview of 2015 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. Core earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash 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 when comparing on an annual basis. In the table below, restructuring costs were incurred in each of the three year periods; however, these costs relate to different restructuring programs. Amounts excluded for 2015 relate to derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), deferred tax asset valuation allowance, restructuring costs and repatriation of funds to the U.S. Amounts excluded for 2014 relate to derivatives and financial instrument fair value changes, asset impairments (including an impairment of goodwill), our divestiture programs and related gains on asset sales and restructuring costs, repatriation of proceeds to the U.S., loss on early retirement of debt and deferred income tax on the formation of the General Partner. Amounts excluded for 2013 relate to derivatives and financial instrument fair value changes, asset impairments, our divestiture programs and related repatriation of proceeds to the U.S. and restructuring costs. For more information on our restructuring programs, see Note 6 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.

Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.


	Year Ended December 31,
	2015			2014			2013
	(Millions, except per share amounts)
Net earnings (loss) attributable to Devon (GAAP)	$	(14,454	)	$	1,607		$	(20	)
Adjustments (net of taxes and noncontrolling interests):
Derivatives and other financial instruments		(206	)		(1,262	)		131
Cash settlements on derivatives and financial instruments		1,552			31			139

Noncash effect of derivatives and financial instruments		1,346			(1,231	)		270
Asset impairments		13,100			1,948			1,353
Deferred tax asset valuation allowance		967			—			—
Gain on asset sales and repatriations		33			(421	)		97
Investment in General Partner deferred income tax		—			48			—
Restructuring costs		52			35			34
Early retirement of debt		—			31			—

Core earnings attributable to Devon (non-GAAP)	$	1,044		$	2,017		$	1,734

Earnings (loss) per share attributable to Devon (GAAP)	$	(35.55	)	$	3.91		$	(0.06	)
Adjustments (net of taxes and noncontrolling interests):
Derivatives and other financial instruments		(0.49	)		(3.07	)		0.31
Cash settlements on derivatives and financial instruments		3.80			0.08			0.34

Noncash effect of derivatives and financial instruments		3.31			(2.99	)		0.65
Asset impairments		32.18			4.74			3.35
Deferred tax asset valuation allowance		2.37			—			—
Gain on asset sales and repatriations		0.08			(1.02	)		0.24
Investment in General Partner deferred income tax		—			0.12			—
Restructuring costs		0.13			0.08			0.08
Early retirement of debt		—			0.07			—

Core earnings per share attributable to Devon (non-GAAP)	$	2.52		$	4.91		$	4.26

Previous: Item 6. Selected Financial Data · Next: Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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

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

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