Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-Q

 

 

(Mark One)

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013

or

 

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-32318

 

 

DEVON ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		73-1567067
(State of other jurisdiction of incorporation or organization)		(I.R.S. Employer identification No.)
333 West Sheridan Avenue, Oklahoma City, Oklahoma		73102-5015
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (405) 235-3611

Former name, address and former fiscal year, if changed from last report: Not applicable

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes   þ    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer		þ		Accelerated filer		¨
Non-accelerated filer		¨  (Do not check if a smaller reporting company)		Smaller reporting company		¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).    Yes   ¨    No  þ

On April 24, 2013, 406 million shares of common stock were outstanding.

 

 

 

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Table of Contents

DEVON ENERGY CORPORATION

FORM 10-Q

TABLE OF CONTENTS

 

Part I Financial Information
Item 1. Consolidated Financial Statements			3
Consolidated Comprehensive Statements of Earnings			3
Consolidated Statements of Cash Flows			4
Consolidated Balance Sheets			5
Consolidated Statements of Stockholders’ Equity			6
Notes to Consolidated Financial Statements			7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
Item 3. Quantitative and Qualitative Disclosures About Market Risk			30
Item 4. Controls and Procedures			30
Part II Other Information
Item 1. Legal Proceedings			32
Item 1A. Risk Factors			32
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			32
Item 3. Defaults Upon Senior Securities			32
Item 4. Mine Safety Disclosures			32
Item 5. Other Information			32
Item 6. Exhibits			33
Signatures			34

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding our expectations and plans, as well as future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2012 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and NGLs and related products and services; exploration or drilling programs; political or regulatory events; general economic and financial market conditions; and other factors discussed in this report.

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS

 

		Three Months Ended March 31,
		2013				2012
		(Unaudited) (In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales		$	1,804			$	1,915
Oil, gas and NGL derivatives			(320	)			145
Marketing and midstream revenues			488				437
Total revenues			1,972				2,497
Expenses and other, net:
Lease operating expenses			525				514
Marketing and midstream operating costs and expenses			363				325
Depreciation, depletion and amortization			704				680
General and administrative expenses			150				168
Taxes other than income taxes			113				102
Interest expense			110				87
Restructuring costs			38				—
Asset impairments			1,913				—
Other, net			18				10
Total expenses and other, net			3,934				1,886
Earnings (loss) from continuing operations before income taxes			(1,962	)			611
Current income tax expense			—				18
Deferred income tax expense (benefit)			(623	)			179
Earnings (loss) from continuing operations			(1,339	)			414
Loss from discontinued operations, net of tax			—				(21	)
Net earnings (loss)		$	(1,339	)		$	393
Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share		$	(3.34	)		$	1.03
Basic loss from discontinued operations per share			—				(0.06	)
Basic net earnings (loss) per share		$	(3.34	)		$	0.97
Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share		$	(3.34	)		$	1.03
Diluted loss from discontinued operations per share			—				(0.06	)
Diluted net earnings (loss) per share		$	(3.34	)		$	0.97
Comprehensive earnings (loss):
Net earnings (loss)		$	(1,339	)		$	393
Other comprehensive earnings (loss), net of tax:
Foreign currency translation			(183	)			152
Pension and postretirement plans			4				4
Other comprehensive earnings (loss), net of tax			(179	)			156
Comprehensive earnings (loss)		$	(1,518	)		$	549

See accompanying notes to consolidated financial statements.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Three Months
		Ended March 31,
		2013				2012
		(Unaudited)
		(In millions)
Cash flows from operating activities:
Net earnings (loss)		$	(1,339	)		$	393
Loss from discontinued operations, net of tax			—				21
Adjustments to reconcile earnings from continuing operations to net cash from operating activities:
Depreciation, depletion and amortization			704				680
Asset impairments			1,913				—
Deferred income tax expense (benefit)			(623	)			179
Unrealized change in fair value of financial instruments			419				22
Other noncash charges			83				54
Net increase in working capital			(158	)			(321	)
Increase in long-term other assets			(6	)			(12	)
Increase (decrease) in long-term other liabilities			9				(16	)
Cash from operating activities – continuing operations			1,002				1,000
Cash from operating activities – discontinued operations			—				26
Net cash from operating activities			1,002				1,026
Cash flows from investing activities:
Capital expenditures			(1,926	)			(2,088	)
Proceeds from property and equipment divestitures			29				—
Purchases of short-term investments			(871	)			(827	)
Redemptions of short-term investments			1,988				1,048
Other			(2	)			(1	)
Cash from investing activities – continuing operations			(782	)			(1,868	)
Cash from investing activities – discontinued operations			—				58
Net cash from investing activities			(782	)			(1,810	)
Cash flows from financing activities:
Net short-term borrowings			508				357
Credit facility borrowings			—				750
Proceeds from stock option exercises			—				20
Dividends paid on common stock			(81	)			(80	)
Excess tax benefits related to share-based compensation			3				1
Net cash from financing activities			430				1,048
Effect of exchange rate changes on cash			(12	)			9
Net change in cash and cash equivalents			638				273
Cash and cash equivalents at beginning of period			4,637				5,555
Cash and cash equivalents at end of period		$	5,275			$	5,828

See accompanying notes to consolidated financial statements.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

		March 31,				December 31,
		2013				2012
		(Unaudited)
		(In millions, except share data)
ASSETS
Current assets:
Cash and cash equivalents		$	5,275			$	4,637
Short-term investments			1,226				2,343
Accounts receivable			1,369				1,245
Other current assets			533				746
Total current assets			8,403				8,971
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization			70,431				69,410
Not subject to amortization			3,426				3,308
Total oil and gas			73,857				72,718
Other			5,792				5,630
Total property and equipment, at cost			79,649				78,348
Less accumulated depreciation, depletion and amortization			(53,267	)			(51,032	)
Property and equipment, net			26,382				27,316
Goodwill			6,017				6,079
Other long-term assets			780				960
Total assets		$	41,582			$	43,326
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	1,409			$	1,451
Revenues and royalties payable			753				750
Short-term debt			4,197				3,189
Other current liabilities			441				613
Total current liabilities			6,800				6,003
Long-term debt			7,955				8,455
Asset retirement obligations			2,092				1,996
Other long-term liabilities			873				901
Deferred income taxes			4,154				4,693
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 406 million shares in 2013 and 2012, respectively			41				41
Additional paid-in capital			3,717				3,688
Retained earnings			14,358				15,778
Accumulated other comprehensive earnings			1,592				1,771
Total stockholders’ equity			19,708				21,278
Commitments and contingencies (Note 16)
Total liabilities and stockholders’ equity		$	41,582			$	43,326

See accompanying notes to consolidated financial statements.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

 

		Common Stock								Additional Paid-In				Retained				Accumulated Other Comprehensive				Treasury				Total Stockholders’
		Shares				Amount				Capital				Earnings				Earnings				Stock				Equity
		(Unaudited)
		(In millions)
Three Months Ended March 31, 2013
Balance as of December 31, 2012			406			$	41			$	3,688			$	15,778			$	1,771			$	—			$	21,278
Net loss			—				—				—				(1,339	)			—				—				(1,339	)
Other comprehensive loss, net of tax			—				—				—				—				(179	)			—				(179	)
Common stock repurchased			—				—				—				—				—				(6	)			(6	)
Common stock retired			—				—				(6	)			—				—				6				—
Common stock dividends			—				—				—				(81	)			—				—				(81	)
Share-based compensation			—				—				32				—				—				—				32
Share-based compensation tax benefits			—				—				3				—				—				—				3
Balance as of March 31, 2013			406			$	41			$	3,717			$	14,358			$	1,592			$	—			$	19,708
Three Months Ended March 31, 2012
Balance as of December 31, 2011			404			$	40			$	3,507			$	16,308			$	1,575			$	—			$	21,430
Net earnings			—				—				—				393				—				—				393
Other comprehensive earnings, net of tax			—				—				—				—				156				—				156
Stock option exercises			—				—				20				—				—				—				20
Common stock repurchased			—				—				—				—				—				(1	)			(1	)
Common stock retired			—				—				(1	)			—				—				1				—
Common stock dividends			—				—				—				(80	)			—				—				(80	)
Share-based compensation			—				—				37				—				—				—				37
Share-based compensation tax benefits			—				—				1				—				—				—				1
Balance as of March 31, 2012			404			$	40			$	3,564			$	16,621			$	1,731			$	—			$	21,956

See accompanying notes to consolidated financial statements.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

The accompanying unaudited financial statements and notes of Devon Energy Corporation (“Devon”) have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying financial statements and notes should be read in conjunction with the accompanying financial statements and notes included in Devon’s 2012 Annual Report on Form 10-K.

The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary to a fair statement of Devon’s results of operations and cash flows for the three-month periods ended March 31, 2013 and 2012 and Devon’s financial position as of March 31, 2013.

2. Derivative Financial Instruments

Objectives and Strategies

Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and typically include financial price swaps, basis swaps, costless price collars and call options.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates.

Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.

Counterparty Credit Risk

By using derivative financial instruments, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts contain provisions that provide for collateral payments, depending on levels of exposure and the credit rating of the counterparty. As of March 31, 2013, Devon did not hold any collateral from its counterparties.

Commodity Derivatives

As of March 31, 2013, Devon had the following open oil derivative positions. Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price.

 

		Price Swaps								Price Collars												Call Options Sold
Period		Volume (Bbls/d)				Weighted Average Price ($/Bbl)				Volume (Bbls/d)				Weighted Average Floor Price ($/Bbl)				Weighted Average Ceiling Price ($/Bbl)				Volume (Bbls/d)				Weighted Average Price ($/Bbl)
Q2-Q4 2013			70,000			$	100.26				65,000			$	90.13			$	111.91				10,000			$	120.00
Q1-Q4 2014			21,000			$	94.99				10,000			$	86.53			$	102.75				39,000			$	116.15
Q1-Q4 2015			500			$	91.00				—			$	—			$	—				19,000			$	114.74

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

		Basis Swaps
Period		Index		Volume (Bbls/d)				Weighted Average Differential to WTI ($/Bbl)
Q2-Q4 2013		Western Canadian Select			31,169			$	(22.03	)

As of March 31, 2013, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas swaps and collars that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas swaps and collars that settle against the AECO index.

 

		Price Swaps								Price Collars												Call Options Sold
Period		Volume (MMBtu/d)				Weighted Average Price ($/MMBtu)				Volume (MMBtu/d)				Weighted Average Floor Price ($/MMBtu)				Weighted Average Ceiling Price ($/MMBtu)				Volume (MMBtu/d)				Weighted Average Price ($/MMBtu)
Q2-Q4 2013			987,500			$	4.09				749,273			$	3.55			$	4.19				—			$	—
Q1-Q4 2014			725,000			$	4.39				30,000			$	4.00			$	4.55				500,000			$	5.00
Q1-Q4 2015			—			$	—				—			$	—			$	—				475,000			$	5.11

 

		Price Swaps
Period		Volume (MMBtu/d)				Weighted Average  Price ($/MMBtu)
Q2-Q4 2013			28,435			$	3.64

As of March 31, 2013, Devon had the following open NGL derivative positions. Devon’s NGL swaps settle against the average of the prompt month OPIS Mont Belvieu, Texas hub.

 

		Price Swaps
Period		Product				Volume (Bbls/d)				Weighted Average  Price ($/Bbl)
Q2-Q4 2013			Propane				1,364			$	40.88
Q2-Q4 2013			Ethane				2,945			$	14.25

 

		Basis Swaps
Period		Pay				Volume (Bbls/d)				Weighted Average Differential to WTI ($/Bbl)
Q2-Q4 2013			Natural Gasoline				500			$(6.80)

Interest Rate Derivatives

As of March 31, 2013, Devon had the following open interest rate derivative positions:

 

Notional		Weighted Average Fixed Rate Received		Variable Rate Paid				Expiration
(In millions)
$750		3.88%			Federal funds rate				July 2013

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Foreign Currency Derivatives

As of March 31, 2013, Devon had the following open foreign currency derivative positions:

 

Forward Contract

Currency

Contract Type

CAD Notional

Weighted Average Fixed Rate Received

Expiration

(In millions)

(CAD-USD)

Canadian Dollar

Sell

$

755

0.979

May 2013

Financial Statement Presentation

The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s commodity derivatives are presented in the “Oil, gas and NGL derivatives” caption in the accompanying comprehensive statements of earnings. Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s interest rate and foreign currency derivatives are presented in the “Other, net” caption in the accompanying comprehensive statements of earnings.

 

		Three Months Ended March  31,
		2013				2012
		(In millions)
Cash settlements:
Commodity derivatives		$	86			$	158
Interest rate derivatives			9				10
Foreign currency derivatives			19				(11	)
Total cash settlements			114				157
Unrealized gains (losses):
Commodity derivatives			(406	)			(13	)
Interest rate derivatives			(9	)			(10	)
Foreign currency derivatives			(4	)			1
Total unrealized losses			(419	)			(22	)
Net gain (loss) recognized on comprehensive statements of earnings		$	(305	)		$	135

The following table presents the derivative fair values included in the accompanying balance sheets.

 

		Balance Sheet Caption		March 31, 2013				December 31, 2012
				(In millions)
Asset derivatives:
Commodity derivatives		Other current assets		$	91			$	379
Commodity derivatives		Other long-term assets			63				22
Interest rate derivatives		Other current assets			14				23
Foreign currency derivatives		Other current assets			—				1
Total asset derivatives				$	168			$	425

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

		Balance Sheet Caption		March 31, 2013				December 31, 2012
				(In millions)
Liability derivatives:
Commodity derivatives		Other current liabilities		$	79			$	3
Commodity derivatives		Other long-term liabilities			112				29
Foreign currency derivatives		Other current liabilities			3				—
Total liability derivatives				$	194			$	32

3. Restructuring Costs

Office Consolidation

In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s headquarters in Oklahoma City. As of March 31, 2013, Devon had substantially completed this initiative and incurred $118 million of restructuring costs associated with the office consolidation.

Divestiture of Offshore Assets

In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of March 31, 2013, Devon had divested all of its U.S. Offshore and International assets and incurred $196 million of restructuring costs associated with the divestitures.

Financial Statement Presentation

The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings related to the office consolidation. There were no costs related to the offshore divestitures in the three months ended March 31, 2013 and 2012, respectively.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Lease obligations and other		$	29			$	—
Asset impairments			9				—
Restructuring costs		$	38			$	—

In the three months ended March 31, 2013, Devon incurred $23 million of restructuring costs related to office space that is subject to non-cancellable operating lease agreements that Devon ceased using as a part of the office consolidation. Devon also recognized $9 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The schedule below summarizes Devon’s restructuring liabilities.

 

		Other Current Liabilities				Other Long-Term Liabilities				Total
						(In millions)
Balance as of December 31, 2011		$	29			$	16			$	45
Lease obligations—Offshore			(2	)			(1	)			(3	)
Employee severance—Offshore			(2	)			—				(2	)
Balance as March 31, 2012		$	25			$	15			$	40
Balance as of December 31, 2012		$	52			$	9			$	61
Lease obligations and other—Office consolidation			11				9				20
Employee severance—Office consolidation			(9	)			—				(9	)
Lease obligations—Offshore			(1	)			—				(1	)
Balance as of March 31, 2013		$	53			$	18			$	71

4. Other, net

The components of other, net in the accompanying comprehensive statements of earnings include the following:

 

		Three Months Ended
		March 31,
		2013				2012
		(In millions)
Accretion of asset retirement obligations		$	28			$	27
Foreign currency derivatives			(15	)			10
Foreign exchange loss (gain)			17				(14	)
Interest income			(8	)			(7	)
Other			(4	)			(6	)
Other, net		$	18			$	10

5. Earnings (Loss) Per Share

The following table reconciles earnings (loss) from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share.

 

		Earnings (loss)				Common Shares				Earnings (loss) per Share
		(In millions, except per share amounts)
Three Months Ended March 31, 2013:
Loss from continuing operations		$	(1,339	)			406
Attributable to participating securities			(1	)			(4	)
Basic and diluted loss per share		$	(1,340	)			402			$	(3.34	)

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

		Earnings (loss)				Common Shares				Earnings (loss) per Share
		(In millions, except per share amounts)
Three Months Ended March 31, 2012:
Earnings from continuing operations		$	414				404
Attributable to participating securities			(4	)			(4	)
Basic earnings per share			410				400			$	1.03
Dilutive effect of potential common shares issuable			—				1
Diluted earnings per share		$	410				401			$	1.03

Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. These excluded options totaled 7.7 million shares and 6.4 million shares during the three-month periods ended March 31, 2013 and 2012, respectively.

6. Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

 

		Three Months Ended
		March 31,
		2013				2012
		(In millions)
Foreign currency translation:
Beginning accumulated foreign currency translation		$	1,996			$	1,802
Change in cumulative translation adjustment			(191	)			159
Income tax benefit (expense)			8				(7	)
Ending accumulated foreign currency translation			1,813				1,954
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits			(225	)			(227	)
Recognition of net actuarial loss and prior service cost in earnings (1)			6				7
Income tax expense			(2	)			(3	)
Ending accumulated pension and postretirement benefits			(221	)			(223	)
Accumulated other comprehensive earnings, net of tax		$	1,592			$	1,731

 

(1)	These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost which, is a component of general and administrative expenses on the accompanying comprehensive statements of earnings (see retirement plans footnote for additional details).

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

7. Supplemental Information to Statements of Cash Flows

 

		Three Months Ended March  31,
		2013				2012
		(In millions)
Net change in working capital:
Change in accounts receivable		$	(122	)		$	280
Change in other current assets			(1	)			(53	)
Change in accounts payable			83				(226	)
Change in revenues and royalties payable			3				(169	)
Change in income taxes payable			9				(16	)
Change in other current liabilities			(130	)			(137	)
Net increase in working capital		$	(158	)		$	(321	)
Interest paid (net of capitalized interest)		$	139			$	136
Income taxes paid (received)		$	(11	)		$	33

8. Short-Term Investments

The components of short-term investments include the following:

 

		March 31, 2013				December 31, 2012
		(In millions)
Canadian treasury, agency and provincial securities		$	1,177			$	1,865
U.S. treasuries			—				429
Other			49				49
Short-term investments		$	1,226			$	2,343

9. Accounts Receivable

The components of accounts receivable include the following:

 

		March 31, 2013				December 31, 2012
		(In millions)
Oil, gas and NGL sales		$	849			$	752
Joint interest billings			331				270
Marketing and midstream revenues			160				161
Other			39				72
Gross accounts receivable			1,379				1,255
Allowance for doubtful accounts			(10	)			(10	)
Net accounts receivable		$	1,369			$	1,245

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

10. Property and Equipment

Asset Impairments

In the first quarter of 2013, Devon recognized asset impairments related to its oil and gas property and equipment as presented below.

 

		Three Months Ended March 31, 2013
		Gross				Net of Taxes
		(In millions)
U.S. oil and gas assets		$	1,110			$	707
Canada oil and gas assets			803				601
Total asset impairments		$	1,913			$	1,308

Under the full-cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months.

The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings since December 31, 2012. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which have reduced proved reserve values.

If pricing conditions do not improve, Devon may incur a full cost ceiling impairment related to its oil and gas property and equipment in future quarters of 2013.

11. Goodwill

During the first three months of 2013, Devon’s Canadian goodwill decreased $62 million entirely due to foreign currency translation.

12. Debt

Commercial Paper

As of March 31, 2013, Devon had $3.7 billion of outstanding commercial paper at an average rate of 0.35 percent.

Credit Lines

Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of March 31, 2013 there were no borrowings under the Senior Credit Facility. The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65 percent. As of March 31, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 26.3 percent.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

13. Asset Retirement Obligations

The schedule below summarizes changes in Devon’s asset retirement obligations.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Asset retirement obligations as of beginning of period		$	2,095			$	1,563
Liabilities incurred			43				21
Liabilities settled			(28	)			(15	)
Revision of estimated obligation			63				399
Liabilities assumed by others			(4	)			(1	)
Accretion expense on discounted obligation			28				27
Foreign currency translation adjustment			(26	)			14
Asset retirement obligations as of end of period			2,171				2,008
Less current portion			79				64
Asset retirement obligations, long-term		$	2,092			$	1,944

14. Retirement Plans

The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.

 

		Pension Benefits								Postretirement Benefits
		Three Months Ended March 31,								Three Months Ended March 31,
		2013				2012				2013				2012
		(In millions)
Service cost		$	9			$	11			$	—			$	—
Interest cost			13				15				—				1
Expected return on plan assets			(15	)			(16	)			—				—
Amortization of prior service cost (1)			1				1				—				—
Net actuarial loss (1)			5				6				—				—
Net periodic benefit cost (2)		$	13			$	17			$	—			$	1

 

(1)	These net periodic benefit costs were reclassified out of comprehensive earnings in the current period.

(2)	Net periodic benefit cost is a component of general and administrative expenses on the accompanying comprehensive statements of earnings.

15. Stockholders’ Equity

Dividends

Devon paid common stock dividends of $81 million and $80 million in the first three months of 2013 and 2012, respectively. The quarterly cash dividend was $0.20 per share for both periods. In March 2013, Devon announced an increase of its quarterly cash dividend to $0.22 per share that will begin in the second quarter of 2013.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

16. Commitments and Contingencies

Devon is party to various legal actions arising in the normal course of business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to involve future amounts that would be material to Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates.

Royalty Matters

Numerous natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with natural gas and NGLs produced and sold. Devon’s largest exposure for such matters relates to royalties in New Mexico. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.

Environmental Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be material.

Chief Redemption Matters

In 2006, Devon acquired Chief Holdings LLC (“Chief”) from the owners of Chief, including Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition against Rees-Jones, as the former majority owner of Chief, and Devon, as Chief’s successor pursuant to the 2006 acquisition. The petition claimed, among other things, violations of the Texas Securities Act, fraud and breaches of Rees-Jones’ fiduciary responsibility to the former owner in connection with Chief’s 2004 redemption of the owner’s minority ownership stake in Chief.

On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133 million of the judgment was also issued against Devon. Devon did not have a legal right of set off with respect to the judgment. Therefore, it had recorded a $133 million long-term liability relating to the judgment with an offsetting $133 million long-term receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant to the indemnification agreement.

The plaintiffs and Rees-Jones have settled all claims related to the 2004 redemption. Under the terms of the settlement, Rees-Jones and Devon received full releases for all of the plaintiffs’ claims with Rees-Jones funding all settlement payments. Consequently, Devon reversed the previously recorded liability and asset in the first quarter of 2013.

Other Matters

Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

17. Fair Value Measurements

The following tables provide carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other payables and accrued expenses included in the accompanying balance sheets approximated fair value at March 31, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables.

 

										Fair Value Measurements Using:
		Carrying				Total Fair				Level 1				Level 2				Level 3
		Amount				Value				Inputs				Inputs				Inputs
		(In millions)
March 31, 2013 assets (liabilities):
Cash equivalents		$	4,653			$	4,653			$	609			$	4,044			$	—
Short-term investments		$	1,226			$	1,226			$	—			$	1,226			$	—
Long-term investments		$	63			$	63			$	—			$	—			$	63
Commodity derivatives		$	154			$	154			$	—			$	154			$	—
Commodity derivatives		$	(191	)		$	(191	)		$	—			$	(191	)		$	—
Interest rate derivatives		$	14			$	14			$	—			$	14			$	—
Foreign currency derivatives		$	(3	)		$	(3	)		$	—			$	(3	)		$	—
Debt		$	(12,152	)		$	(13,423	)		$	—			$	(13,423	)		$	—
December 31, 2012 assets (liabilities):
Cash equivalents		$	4,149			$	4,149			$	200			$	3,949			$	—
Short-term investments		$	2,343			$	2,343			$	429			$	1,914			$	—
Long-term investments		$	64			$	64			$	—			$	—			$	64
Commodity derivatives		$	401			$	401			$	—			$	401			$	—
Commodity derivatives		$	(32	)		$	(32	)		$	—			$	(32	)		$	—
Interest rate derivatives		$	23			$	23			$	—			$	23			$	—
Foreign currency derivatives		$	1			$	1			$	—			$	1			$	—
Debt		$	(11,644	)		$	(13,435	)		$	—			$	(13,435	)		$	—

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.

Level 2 Fair Value Measurements

Cash equivalents and short-term investments — Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value approximates the carrying value.

Commodity, interest rate and foreign currency derivatives — The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.

Debt — Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair values of Devon’s variable-rate commercial paper and credit facility borrowings are the carrying values.

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Level 3 Fair Value Measurements

Long-term investments — Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of March 31, 2013 and December 31, 2012.

Debt — Devon’s Level 3 debt consisted of a non-interest bearing promissory note. Due to the lack of an active market, quoted marked prices for this note, or similar notes, were not available. Therefore, Devon used valuation techniques that relied on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt was estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125 percent interest rate.

Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first three months of 2013 and 2012.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Long-term investments balance at beginning of period		$	64			$	84
Redemptions of principal			(1	)			—
Long-term investments balance at end of period		$	63			$	84
		Three Months Ended March 31,
		2013				2012
		(In millions)
Debt balance at beginning of period		$	—			$	(85	)
Foreign exchange translation adjustment			—				(2	)
Redemptions of principal			—				50
Debt balance at end of period		$	—			$	(37	)

 

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DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

18. Segment Information

Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s segments are all primarily engaged in oil and gas producing activities. Revenues are all from external customers.

 

		U.S.				Canada				Total
		(In millions)
Three Months Ended March 31, 2013:
Oil, gas and NGL sales		$	1,290			$	514			$	1,804
Oil, gas and NGL derivatives		$	(295	)		$	(25	)		$	(320	)
Marketing and midstream revenues		$	438			$	50			$	488
Depreciation, depletion and amortization		$	469			$	235			$	704
Interest expense		$	96			$	14			$	110
Asset impairments		$	1,110			$	803			$	1,913
Loss from continuing operations before income taxes		$	(1,087	)		$	(875	)		$	(1,962	)
Income tax benefit		$	(395	)		$	(228	)		$	(623	)
Loss from continuing operations		$	(692	)		$	(647	)		$	(1,339	)
Property and equipment, net		$	18,082			$	8,300			$	26,382
Total assets		$	23,614			$	17,968			$	41,582
Capital expenditures		$	1,254			$	584			$	1,838
Three Months Ended March 31, 2012:
Oil, gas and NGL sales		$	1,236			$	679			$	1,915
Oil, gas and NGL derivatives		$	145			$	—			$	145
Marketing and midstream revenues		$	399			$	38			$	437
Depreciation, depletion and amortization		$	431			$	249			$	680
Interest expense		$	71			$	16			$	87
Earnings from continuing operations before income taxes		$	533			$	78			$	611
Income tax expense		$	185			$	12			$	197
Earnings from continuing operations		$	348			$	66			$	414
Property and equipment, net		$	18,103			$	8,458			$	26,561
Total assets		$	23,842			$	18,763			$	42,605
Capital expenditures		$	1,436			$	510			$	1,946

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month period ended March 31, 2013, compared to the three-month period ended March 31, 2012, and in our financial condition and liquidity since December 31, 2012. For information regarding our critical accounting policies and estimates, see our 2012 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Overview of 2013 Results

Key components of our financial performance are summarized below, which exclude amounts from our discontinued operations.

 

		Three Months Ended March 31,
		2013				2012				Change
		($ in millions, except per share amounts)
Net earnings (loss)		$	(1,339	)		$	414				-423	%
Adjusted earnings (1)		$	270			$	427				-37	%
Earnings (loss) per share		$	(3.34	)		$	1.03				-426	%
Adjusted earnings per share (1)		$	0.66			$	1.05				-37	%
Production (MBoe/d)			686.9				693.6				-1	%
Realized price per Boe		$	29.18			$	30.33				-4	%
Operating margin per Boe (2)		$	18.06			$	20.80				-13	%
Operating cash flow		$	1,002			$	1,000				+0	%
Adjusted operating cash flow (1)		$	1,157			$	1,349				-14	%
Capitalized costs		$	1,838			$	1,946				-6	%
Shareholder distributions		$	81			$	80				+1	%

 

 

(1)

Adjusted earnings, adjusted earnings per share and adjusted operating cash flow are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (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 2.

(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.

Our net loss in the first three months of 2013 resulted from noncash asset impairments, which reduced our earnings by $1.9 billion ($1.3 billion after tax). Excluding the asset impairments and other items typically excluded by securities analysts, our adjusted earnings were $270 million, or $0.66 per diluted share. This compares to adjusted earnings of $427 million, or $1.05 per diluted share, in the first three months 2012. Earnings were lower in 2013 primarily because of lower oil and NGL prices.

 

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Results of Operations

Production, Prices and Revenues

 

		Three Months Ended March 31,
		2013				2012				Change
Oil (MBbls/d)
U.S.			67.5				54.7				+23	%
Canada			40.5				41.2				-2	%
Total			108.0				95.9				+13	%
Bitumen (MBbls/d)
Canada			54.3				46.1				+18	%
Gas (MMcf/d)
U.S.			1,968.9				2,071.8				-5	%
Canada			455.1				556.4				-18	%
Total			2,424.0				2,628.2				-8	%
NGLs (MBbls/d)
U.S.			110.4				102.1				+8	%
Canada			10.1				11.4				-11	%
Total			120.5				113.5				+6	%
Combined (MBoe/d)
U.S.			506.1				502.2				+1	%
Canada			180.8				191.4				-6	%
Total			686.9				693.6				-1	%
		Three Months Ended March 31,
		2013 (1)				2012 (1)				Change
Oil (per Bbl)
U.S.		$	87.45			$	99.35				-12	%
Canada		$	57.12			$	74.92				-24	%
Total		$	76.08			$	88.86				-14	%
Bitumen (per Bbl)
Canada		$	28.42			$	50.99				-44	%
Gas (per Mcf)
U.S.		$	2.81			$	2.28				+23	%
Canada		$	3.02			$	2.54				+19	%
Total		$	2.85			$	2.34				+22	%
NGLs (per Bbl)
U.S.		$	26.28			$	33.37				-21	%
Canada		$	47.33			$	54.18				-13	%
Total		$	28.04			$	35.46				-21	%
Combined (per Boe)
U.S.		$	28.32			$	27.03				+5	%
Canada		$	31.59			$	39.00				-19	%
Total		$	29.18			$	30.33				-4	%

 

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

 

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The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended March 31, 2013 and 2012.

 

		Three Months Ended March 31,
		Oil				Bitumen				Gas				NGLs				Total
		(In millions)
2012 sales		$	776			$	214			$	559			$	366			$	1,915
Change due to volumes			88				35				(49	)			18				92
Change due to prices			(125	)			(109	)			111				(80	)			(203	)
2013 sales		$	739			$	140			$	621			$	304			$	1,804

Upstream sales increased $92 million due to an 11 percent increase in our liquids production, partially offset by an 8 percent decline in our gas production in the first three months of 2013. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $88 million. Bitumen sales increased $35 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $18 million primarily as a result of continued drilling in the liquids-rich gas portions of the Cana-Woodford and Barnett Shales and the Permian Basin. These increases were partially offset by decreases in our gas production, which resulted in a $49 million decline in sales.

Production information for our key properties is summarized below:

 

•

Permian Basin production increased 20 percent compared to the first quarter of 2012 and 2 percent compared to the fourth quarter of 2012. Oil production accounted for 60 percent of our 68,000 Boe per day produced in the Permian Basin during the first quarter of 2013. The year-over-year increase in total production was driven by a 24 percent increase in oil production.

 

•

Barnett Shale production increased 1 percent compared to the first quarter of 2012 and 2 percent compared to the fourth quarter of 2012. Liquids production accounted for 24 percent of our 1.4 Bcfe per day produced in the Barnett Shale during the first quarter of 2013. The year-over-year increase in total production was driven by a 5 percent increase in liquids production.

 

•

Cana-Woodford Shale production increased 26 percent compared to the first quarter of 2012 and 4 percent compared to the fourth quarter of 2012. Liquids production accounted for 41 percent of our 340 MMcfe per day produced in Cana during the first quarter of 2013. The year-over-year increase in total production was driven by a 78 percent increase in liquids production.

 

•

Jackfish production increased 18 percent compared to the first quarter of 2012 and 11 percent compared to the fourth quarter of 2012. Bitumen production accounted for all of our 54,000 Boe per day produced at Jackfish during the first quarter of 2013.

 

•

Granite Wash production decreased 13 percent compared to the first quarter of 2012. Although total production was down, oil production increased 25 percent compared to the first quarter of 2012. Liquids production accounted for 52 percent of our 16,000 Boe per day produced in the Granite Wash during the first quarter of 2013.

 

•

Mississippian production increased 67 percent compared to the fourth quarter of 2012 to 3,000 Boe per day. Oil production accounted for 66 percent of our total production in the Mississippian during the first quarter of 2013.

 

•

Gulf Coast/East Texas production decreased 16 percent compared to the first quarter of 2012. Liquids production accounted for nearly 25 percent of our 333 MMcfe per day produced in Gulf Coast/East Texas during the first quarter of 2013.

 

•

Rocky Mountain production decreased 13 percent compared to the first quarter of 2012. Although total production was down, oil production increased 13 percent compared to the first quarter of 2012. Liquids production accounted for nearly 30 percent of our 326 MMcfe per day produced in the Rocky Mountains during the first quarter of 2013.

 

•

Lloydminster production decreased 8 percent compared to the first quarter of 2012. Oil production accounted for 95 percent of our 30,000 Boe per day produced at Lloydminster during the first quarter of 2013.

Upstream sales decreased $203 million during the first three months of 2013 due to a 4 percent decrease in our realized price without hedges. Our liquids sales were the most significantly impacted with a $314 million decrease in sales due to prices. The largest contributors to the lower liquids prices were a decrease in the average NYMEX West Texas Intermediate

 

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index price along with wider bitumen differentials and lower NGL prices at the Mont Belvieu, Texas hub. The lower realized prices in our liquids were partially offset by higher realized gas prices, which resulted in additional sales of $111 million. 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.

Oil, Gas and NGL Derivatives

A summary of our open commodity derivative positions is included in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report. The following tables provide financial information associated with our commodity derivatives. The first table presents the cash settlements and unrealized gains and losses that are recognized as components of our revenues. The subsequent tables present our oil, bitumen, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Cash settlements:
Gas derivatives		$	53			$	163
Oil derivatives			32				(6	)
NGL derivatives			1				1
Total cash settlements			86				158
Unrealized gains (losses) on fair value changes:
Gas derivatives			(256	)			96
Oil derivatives			(147	)			(109	)
NGL derivatives			(3	)			—
Total unrealized losses on fair value changes			(406	)			(13	)
Oil, gas and NGL derivatives		$	(320	)		$	145

 

		Three Months Ended March 31, 2013
		Oil				Bitumen				Gas				NGLs				Boe
		(Per Bbl)				(Per Bbl)				(Per Mcf)				(Per Bbl)				(Per Boe)
Realized price without hedges		$	76.08			$	28.42			$	2.85			$	28.04			$	29.18
Cash settlements of hedges (1)			3.29				—				0.24				0.13				1.39
Realized price, including cash settlements		$	79.37			$	28.42			$	3.09			$	28.17			$	30.57
		Three Months Ended March, 2012
		Oil				Bitumen				Gas				NGLs				Boe
		(Per Bbl)				(Per Bbl)				(Per Mcf)				(Per Bbl)				(Per Boe)
Realized price without hedges		$	88.86			$	50.99			$	2.34			$	35.46			$	30.33
Cash settlements of hedges			(0.64	)			—				0.68				0.03				2.50
Realized price, including cash settlements		$	88.22			$	50.99			$	3.02			$	35.49			$	32.83

 

(1)	Cash settlements of oil hedges include settlements from our Western Canadian Select basis swaps presented in Note 2 to the financial statements included in “Item 1. Consolidated Financial Statements” of this report.

Cash settlements presented in the tables above represent realized gains or losses related to various commodity derivatives. In addition to cash settlements, we also recognize unrealized changes in the fair values of our commodity derivatives in each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our commodity derivatives incurred a net loss of $320 million and generated a net gain $145 million during the first three months of 2013 and 2012, respectively.

 

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Marketing and Midstream Revenues and Operating Costs and Expenses

 

		Three Months Ended March 31,
		2013				2012				Change
		($ in millions)
Revenues		$	488			$	437				+12	%
Operating costs and expenses			363				325				+12	%
Operating profit		$	125			$	112				+12	%

During the first three months of 2013, marketing and midstream operating profit increased $13 million primarily due to higher gas prices and lower operating expenses.

Lease Operating Expenses (“LOE”)

 

		Three Months Ended March 31,
		2013				2012				Change
LOE ($ in millions):
U.S.		$	288			$	252				+14	%
Canada			237				262				-9	%
Total		$	525			$	514				+2	%
LOE per Boe:
U.S.		$	6.32			$	5.52				+14	%
Canada		$	14.59			$	15.04				-3	%
Total		$	8.49			$	8.15				+4	%

LOE increased $0.34 per Boe during the first three months of 2013. The largest contributor to the higher unit cost is related to our liquids production growth, particularly at the Permian Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We also experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.

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

 

		Three Months Ended March 31,
		2013				2012				Change
DD&A ($ in millions):
Oil & gas properties		$	627			$	616				+2	%
Other properties			77				64				+21	%
Total		$	704			$	680				+3	%
DD&A per Boe:
Oil & gas properties		$	10.13			$	9.77				+4	%
Other properties			1.25				1.01				+24	%
Total		$	11.38			$	10.78				+6	%

DD&A increased during the first three months of 2013 largely due to higher DD&A rates, resulting from our oil and gas drilling and development activities and construction of our new headquarters in Oklahoma City.

 

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General and Administrative Expenses (“G&A”)

 

		Three Months Ended March 31,
		2013				2012				Change
		($ in millions)
Gross G&A		$	283			$	288				-2	%
Capitalized G&A			(99	)			(91	)			+9	%
Reimbursed G&A			(34	)			(29	)			+17	%
Net G&A		$	150			$	168				-11	%
Net G&A per Boe		$	2.43			$	2.67				-9	%

Net G&A and net G&A per Boe decreased during the first three months of 2013 largely due to lower employee compensation and benefits and higher capitalized G&A.

Taxes Other Than Income Taxes

 

		Three Months Ended March 31,
		2013				2012				Change
		($ in millions)
Production		$	60			$	53				+14	%
Ad valorem and other			53				49				+8	%
Taxes other than income taxes		$	113			$	102				+11	%
Percentage of oil, gas and NGL revenue:
Production			3.35	%			2.77	%			+21	%
Ad valorem and other			2.92	%			2.56	%			+14	%
Total			6.27	%			5.33	%			+18	%

Taxes other than income taxes as a percentage of oil, gas and NGL revenue increased primarily due to lower Canadian revenues with no associated production taxes as well as ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL revenues.

Interest Expense

 

		Three Months Ended March 31,
		2013				2012				Change
		($ in millions)
Interest based on debt outstanding		$	118			$	99				+19	%
Capitalized interest			(11	)			(16	)			-35	%
Other			3				4				-27	%
Interest expense		$	110			$	87				+27	%

Interest expense 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.

 

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Restructuring Costs

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Lease obligations and other		$	29			$	—
Asset impairments			9				—
Restructuring costs		$	38			$	—

In the three months ended March 31, 2013, we incurred $38 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $23 million related to office space that is subject to non-cancellable operating lease agreements that we ceased using as a part of the office consolidation. We also recognized $9 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.

Asset Impairments

 

		Three Months Ended March 31, 2013
		Gross				Net of Taxes
		(In millions)
U.S. oil and gas assets		$	1,110			$	707
Canada oil and gas assets			803				601
Total asset impairments		$	1,913			$	1,308

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 10 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

The oil and gas impairments resulted primarily from declines in the U.S. and Canada full cost ceilings since December 31, 2012. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which have reduced proved reserve values.

If pricing conditions do not improve, we may incur full cost ceiling impairments related to our oil and gas property and equipment in future quarters of 2013.

Income Taxes

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

 

		Three Months Ended March 31,
		2013				2012
Total income tax expense (benefit) (in millions)		$	(623	)		$	197
U.S. statutory income tax rate			(35	%)			35	%
State income taxes			(1	%)			1	%
Taxation on Canadian operations			4	%			(3	%)
Other			—				(1	%)
Effective income tax rate			(32	%)			32	%

 

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Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major source and use categories of our cash and short-term investments.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Operating cash flow – continuing operations		$	1,002			$	1,000
Debt activity, net			508				1,107
Divestitures of property and equipment			29				71
Capital expenditures			(1,926	)			(2,088	)
Shareholder distributions			(81	)			(80	)
Other			(11	)			42
Net change in cash and short-term investments		$	(479	)		$	52
Cash and short-term investments at end of period		$	6,501			$	7,110

Operating Cash Flow – Continuing Operations

Net cash provided by operating activities (“operating cash flow”) was our primary source of capital in the first three months of 2013. Our operating cash flow was comparable to the first three months of 2012.

During the first three months of 2013, our operating cash flow funded approximately 50 percent of our cash payments for capital expenditures. Leveraging our liquidity, we used cash balances and short-term debt to fund the remainder of our cash-based capital expenditures.

Debt Activity, Net

During the first three months of 2013, we utilized net commercial paper borrowings of $508 million to fund capital expenditures in excess of our operating cash flow. During the first three months of 2012, we utilized net credit facility and commercial paper borrowings of $1.1 billion to fund capital expenditures in excess of our operating cash flow.

Divestitures of Property and Equipment

In the first quarter of 2012, we received $71 million from the divestiture of our Angola operations.

Capital Expenditures

The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Development		$	1,328			$	1,409
Exploration			228				381
Subtotal			1,556				1,790
Capitalized G&A and interest			108				99
Total oil and gas			1,664				1,889
Midstream			219				114
Corporate and other			43				85
Total capital expenditures		$	1,926			$	2,088

 

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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 $1.7 billion and $1.9 billion in the first three months of 2013 and 2012, respectively. The 12% decline in exploration and development capital spending in the first three months of 2013 was primarily due to utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements.

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 our Access Pipeline in Canada.

Shareholder distributions

The following table summarizes our common stock dividends (amounts in millions) during the first three months of 2013 and 2012. In the first quarter of 2013, we announced a 10% increase for our quarterly dividend to $0.22 per share beginning in the second quarter of 2013.

 

		Three Months Ended March 31,
		2013								2012
		Amount				Per Share				Amount				Per Share
Dividends		$	81			$	0.20			$	80			$	0.20

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. The following sections discuss changes to our liquidity subsequent to filing our 2012 Annual Report on Form 10-K.

Operating Cash Flow

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. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on a portion of our 2013 production. The key terms to our open oil, gas and NGL derivative financial instruments as of March 31, 2013 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

Credit Availability

As of March 31, 2013, we had $2.9 billion of available capacity under our syndicated, unsecured revolving line of credit (the “Senior Credit Facility”), net of letters of credit outstanding. We also have access to $5.0 billion of short-term credit under our commercial paper program. At March 31, 2013, we had $3.7 billion of commercial paper borrowings 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, to be no greater than 65 percent. As of March 31, 2013, we were in compliance with this covenant with a debt-to-capitalization ratio of 26.3 percent.

At March 31, 2013, we held approximately $6.5 billion of cash and short-term investments. Included in this total was $6.1 billion of cash and short-term investments held by our foreign subsidiaries. Based on planned investments to develop and grow our Canadian business, forecasts for our U.S. and Canadian operations, favorable borrowing conditions in the U.S., and existing U.S. income tax laws pertaining to repatriations of foreign earnings, we previously disclosed that we had no current expectations to repatriate the $6.1 billion to the U.S. However, due to our recent activity levels and evolving tax attributes, we expect that our net operating losses for U.S. income tax purposes can be used in conjunction with our foreign tax credits to partially offset current income taxes otherwise due upon repatriating a portion of our foreign cash to the U.S. Therefore, we now expect to repatriate approximately $2 billion to the U.S. Additionally, as we progress through 2013 and gain additional clarity on our current and expected tax attributes, we believe we could repatriate another sizeable amount of cash to the U.S. in a tax-efficient manner in 2013 or 2014. We anticipate using any repatriated funds to repay outstanding commercial paper borrowings.

 

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Non-GAAP Measures

We make reference to “adjusted earnings,” “adjusted earnings per share” and “adjusted cash flow” in “Overview of 2013 Results” in this Item 2 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 represents 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. Adjusted cash flow represents cash flow from operating activities excluding certain balance sheet changes and non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. We believe these non-GAAP measures facilitate comparisons of our performance to earnings and cash flow 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. The amounts below exclude any amounts from our discontinued operations.

Adjusted Earnings and Adjusted Earnings Per Share

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

 

		Three Months Ended March 31,
		2013				2012
		(In millions, except per share amounts)
Net earnings (loss) (GAAP)		$	(1,339	)		$	414
Adjustments (net of taxes):
Asset impairments			1,308				—
Oil, gas and NGL derivatives			269				8
Restructuring costs			24				—
Interest rate and other financial instruments			8				5
Adjusted earnings (Non-GAAP)		$	270			$	427
Earnings (loss) per share (GAAP)		$	(3.34	)		$	1.02
Adjustments (net of taxes):
Asset impairments			3.25				—
Oil, gas and NGL derivatives			0.67				0.02
Restructuring costs			0.06				—
Interest rate and other financial instruments			0.02				0.01
Adjusted earnings per share (Non-GAAP)		$	0.66			$	1.05

Adjusted Cash Flow

Below is a reconciliation of our adjusted operating cash flow to its comparable GAAP measure.

 

		Three Months Ended March 31,
		2013				2012
		(In millions)
Operating cash flow (GAAP)		$	1,002			$	1,000
Adjustments (net of taxes):
Changes in assets and liabilities			155				349
Adjusted operating cash flow (Non-GAAP)		$	1,157			$	1,349

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

We have commodity derivatives that pertain to a portion of our production for the last nine months of 2013, as well as 2014 and 2015. The key terms to our open oil, gas and NGL derivative financial instruments as of March 31, 2013 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At March 31, 2013, a 10 percent change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:

 

		10% Increase				10% Decrease
		(In millions)
Gain (loss):
Gas derivatives		$	(347	)		$	322
Oil derivatives		$	(378	)		$	367
NGL derivatives		$	(3	)		$	3

Interest Rate Risk

At March 31, 2013, we had total debt outstanding of $12.2 billion. Of this amount, $8.5 billion bears fixed interest rates averaging 5.4 percent. The remaining $3.7 billion of commercial paper borrowings bears interest rates that averaged 0.35 percent.

As of March 31, 2013, we had open interest rate swap positions that are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the Federal Funds rate. A 10 percent change in these forward curves would not have materially impacted our balance sheet at March 31, 2013.

Foreign Currency Risk

Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated using an average exchange rate during the reporting period. A 10 percent unfavorable change in the Canadian-to-U.S. dollar exchange rate would not materially impact our March 31, 2013 balance sheet.

Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are sometimes based in Canadian dollars. Additionally, at March 31, 2013, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash. The value of the intercompany loans increases or decreases from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of March  31, 2013, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon, including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of March 31, 2013, to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.

 

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Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II. Other Information

Item 1. Legal Proceedings

There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2012 Annual Report on Form 10-K.

Item 1A. Risk Factors

There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2012 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table provides information regarding purchases of our common stock that were made by us during the first three months of 2013.

 

Period		Total Number of Shares Purchased (1)				Average Price Paid per  Share
January 1 – January 31			34,168			$	54.59
February 1 – February 28			24,595			$	58.57
March 1 – March 31			38,823			$	56.99
Total			97,586			$	56.55

 

(1)	Share repurchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises.

Under the Devon Canada Corporation Savings Plan (the “Canadian Plan”), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. Eligible Canadian employees purchased approximately 3,600 shares of our common stock in the first quarter of 2013, at then-prevailing stock prices, that they held through their ownership in the Canadian Plan. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

 

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Item 6. Exhibits

(a) Exhibits required by Item 601 of Regulation S-K are as follows:

 

Exhibit Number		Description
10.1		Devon Energy Corporation 2013 Amendment (Effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Plan (as Amended and Restated Effective June 6, 2012).
31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

						DEVON ENERGY CORPORATION
Date: May 1, 2013						/s/ Jeffrey A. Agosta
						Jeffrey A. Agosta
						Executive Vice President and Chief Financial Officer

 

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INDEX TO EXHIBITS

 

Exhibit Number		Description
10.1		Devon Energy Corporation 2013 Amendment (Effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term Plan (as Amended and Restated Effective June 6, 2012).
31.1		Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2		Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

 

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