UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended June 30, 2013
or
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
(State of other jurisdiction of
incorporation or organization)
(I.R.S. Employer
identification No.)
333 West Sheridan Avenue,
Oklahoma City, Oklahoma
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.
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 July 18, 2013, 406 million shares of common stock were outstanding.
FORM 10-Q
TABLE OF CONTENTS
Item 1. Consolidated Financial Statements
Consolidated Comprehensive Statements of Earnings
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Stockholders’ Equity
Notes to Consolidated Financial Statements
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
Item 1. Legal Proceedings
Item 1A. Risk Factors
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Mine Safety Disclosures
Item 5. Other Information
Item 6. Exhibits
Signatures
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.
2
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
(Unaudited)
(In millions, except per share amounts)
Revenues:
Oil, gas and NGL sales
Oil, gas and NGL derivatives
Marketing and midstream revenues
Total revenues
Expenses and other, net:
Lease operating expenses
Marketing and midstream operating costs and expenses
Depreciation, depletion and amortization
General and administrative expenses
Taxes other than income taxes
Interest expense
Restructuring costs
Asset impairments
Other, net
Total expenses and other, net
Earnings (loss) from continuing operations before income taxes
Current income tax expense
Deferred income tax expense (benefit)
Earnings (loss) from continuing operations
Loss from discontinued operations, net of tax
Net earnings (loss)
Basic net earnings (loss) per share:
Basic earnings (loss) from continuing operations per share
Basic loss from discontinued operations per share
Basic net earnings (loss) per share
Diluted net earnings (loss) per share:
Diluted earnings (loss) from continuing operations per share
Diluted loss from discontinued operations per share
Diluted net earnings (loss) per share
Comprehensive earnings (loss):
Other comprehensive loss, net of tax:
Foreign currency translation
Pension and postretirement plans
Other comprehensive loss, net of tax
Comprehensive earnings (loss)
See accompanying notes to consolidated financial statements.
3
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Adjustments to reconcile earnings (loss) from continuing operations to net cash from operating activities:
Unrealized change in fair value of financial instruments
Other noncash charges
Net decrease (increase) in working capital
Decrease in long-term other assets
Increase (decrease) in long-term other liabilities
Cash from operating activities – continuing operations
Cash from operating activities – discontinued operations
Net cash from operating activities
Cash flows from investing activities:
Capital expenditures
Proceeds from property and equipment divestitures
Purchases of short-term investments
Redemptions of short-term investments
Other
Cash from investing activities – continuing operations
Cash from investing activities – discontinued operations
Net cash from investing activities
Cash flows from financing activities:
Proceeds from borrowings of long-term debt, net of issuance costs
Net short-term debt repayments
Credit facility borrowings
Credit facility repayments
Proceeds from stock option exercises
Dividends paid on common stock
Excess tax benefits related to share-based compensation
Net cash from financing activities
Effect of exchange rate changes on cash
Net change in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
4
CONSOLIDATED BALANCE SHEETS
ASSETS
Current assets:
Cash and cash equivalents
Short-term investments
Accounts receivable
Other current assets
Total current assets
Property and equipment, at cost:
Oil and gas, based on full cost accounting:
Subject to amortization
Not subject to amortization
Total oil and gas
Total property and equipment, at cost
Less accumulated depreciation, depletion and amortization
Property and equipment, net
Goodwill
Other long-term assets
Total assets
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable
Revenues and royalties payable
Short-term debt
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations
Other long-term liabilities
Deferred income taxes
Stockholders’ equity:
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 406 million shares in 2013 and 2012, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive earnings
Total stockholders’ equity
Commitments and contingencies (Note 17)
Total liabilities and stockholders’ equity
5
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Additional
Paid-In
Six Months Ended June 30, 2013:
Balance as of December 31, 2012
Net loss
Stock option exercises
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Share-based compensation tax benefits
Balance as of June 30, 2013
Six Months Ended June 30, 2012:
Balance as of December 31, 2011
Net earnings
Balance as of June 30, 2012
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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 and six-month periods ended June 30, 2013 and 2012 and Devon’s financial position as of June 30, 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 June 30, 2013, Devon held $39 million of cash collateral. Such amount represented the estimated fair value of certain derivative positions in excess of Devon’s credit guidelines. The collateral is reported in other current liabilities in the accompanying balance sheet.
Commodity Derivatives
As of June 30, 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.
Period
Q3-Q4 2013
Q1-Q4 2014
Q1-Q4 2015
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
As of June 30, 2013, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas derivatives that settle against the AECO index.
As of June 30, 2013, Devon had the following open NGL derivative positions. Devon’s NGL derivatives settle against the average of the prompt month OPIS Mont Belvieu, Texas hub.
Interest Rate Derivatives
As of June 30, 2013, Devon had the following open interest rate derivative position:
Notional
$750
8
Foreign Currency Derivatives
As of June 30, 2013, Devon had the following open foreign currency derivative position:
Forward Contract
Currency
Canadian Dollar
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.
Cash settlements:
Commodity derivatives
Interest rate derivatives
Foreign currency derivatives
Total cash settlements
Unrealized gains (losses):
Total unrealized gains (losses)
Net gains recognized on comprehensive statements of earnings
9
The following table presents the derivative fair values included in the accompanying balance sheets.
Asset derivatives:
Total asset derivatives
Liability derivatives:
Total liability derivatives
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 June 30, 2013, Devon had substantially completed this initiative and incurred $126 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. Devon completed this divestiture program in 2012, having incurred $196 million of cumulative restructuring costs associated with the divestitures.
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-month and six-month periods ended June 30, 2013 and 2012.
Lease obligations and other
In the six months ended June 30, 2013, Devon incurred $25 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 $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.
10
The schedule below summarizes Devon’s restructuring liabilities.
Lease obligations—Offshore
Employee severance—Offshore
Balance as June 30, 2012
Lease obligations and other—Office consolidation
Employee severance—Office consolidation
4. Other, net
The components of other, net in the accompanying comprehensive statements of earnings include the following:
Accretion of asset retirement obligations
Foreign exchange loss
Interest income
5. Income Taxes
In the second quarter of 2013, Devon repatriated to the United States $2.0 billion of cash from its foreign subsidiaries. In conjunction with the repatriation, Devon recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.
As of June 30, 2013, Devon’s unremitted foreign earnings totaled approximately $5.6 billion. Of this amount, approximately $4.4 billion was deemed to be indefinitely reinvested into the development and growth of Devon’s Canadian business. Therefore, Devon has not recognized a deferred tax liability for U.S. income taxes associated with such earnings. If such earnings were to be repatriated to the U.S., Devon may be subject to U.S. income taxes and foreign withholding taxes. However, it is not practical to estimate the amount of such additional taxes that may be payable due to the inter-relationship of the various factors involved in making such an estimate.
11
Devon has deemed the remaining $1.2 billion of unremitted foreign earnings not to be indefinitely reinvested. Consequently, Devon has recognized a deferred tax liability of approximately $550 million associated with such unremitted earnings as of June 30, 2013.
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.
Total income tax expense (benefit) (in millions)
U.S. statutory income tax rate
State income taxes
Taxation on Canadian operations
Effective income tax rate
6. 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.
Three Months Ended June 30, 2013:
Earnings from continuing operations
Attributable to participating securities
Basic earnings per share
Dilutive effect of potential common shares issuable
Diluted earnings per share
Three Months Ended June 30, 2012:
Loss from continuing operations
Diluted loss per share
12
Certain options to purchase shares of Devon’s common stock are excluded from the dilution calculation because the options are antidilutive. During the three-month and six-month periods ended June 30, 2013, 7.6 million shares were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2012, 8.9 million shares and 6.7 million shares, respectively, were excluded from the diluted earnings per share calculations.
7. Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
Foreign currency translation:
Beginning accumulated foreign currency translation
Change in cumulative translation adjustment
Income tax benefit
Ending accumulated foreign currency translation
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits
Recognition of net actuarial loss and prior service cost in earnings (1)
Income tax expense
Ending accumulated pension and postretirement benefits
Accumulated other comprehensive earnings, net of tax
13
8. Supplemental Information to Statements of Cash Flows
Net change in working capital accounts:
Interest paid (net of capitalized interest)
Income taxes paid (received)
9. Short-Term Investments
The components of short-term investments include the following:
Canadian treasury, agency and provincial securities
U.S. treasuries
10. Accounts Receivable
The components of accounts receivable include the following:
Joint interest billings
Gross accounts receivable
Allowance for doubtful accounts
Net accounts receivable
14
11. Property and Equipment
Asset Impairments
In the first six months of 2013, Devon recognized asset impairments related to its oil and gas property and equipment as presented below.
U.S. oil and gas assets
Canada oil and gas assets
Total asset impairments
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 estimated future cash flows decline due to price decreases or other factors, Devon could incur additional full cost ceiling impairments related to its oil and gas property and equipment.
12. Goodwill
During the first six months of 2013, Devon’s Canadian goodwill decreased $162 million entirely due to foreign currency translation.
13. Debt
Commercial Paper
During the second quarter of 2013, Devon repatriated $2.0 billion of foreign earnings to the United States and repaid $2.0 billion of commercial paper borrowings. As of June 30, 2013, Devon had $1.7 billion of outstanding commercial paper at an average rate of 0.36 percent.
Credit Lines
Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of June 30, 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 June 30, 2013, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 22.8 percent.
15
14. Asset Retirement Obligations
The schedule below summarizes changes in Devon’s asset retirement obligations.
Asset retirement obligations as of beginning of period
Liabilities incurred
Liabilities settled
Revision of estimated obligation
Liabilities assumed by others
Accretion expense on discounted obligation
Foreign currency translation adjustment
Asset retirement obligations as of end of period
Less current portion
Asset retirement obligations, long-term
15. Retirement Plans
The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost (1)
Net actuarial loss (gain) (1)
Net periodic benefit cost (2)
16
16. Stockholders’ Equity
Dividends
Devon paid common stock dividends of $170 million and $162 million in the first six months of 2013 and 2012, respectively. The quarterly cash dividend was $0.20 per share in the first and second quarter of 2012 and in the first quarter of 2013. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013.
17. 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, Devon 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.
17
18. 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 June 30, 2013 and December 31, 2012. Therefore, such financial assets and liabilities are not presented in the following tables.
June 30, 2013 assets (liabilities):
Cash equivalents
Long-term investments
Debt
December 31, 2012 assets (liabilities):
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 value of Devon’s variable-rate commercial paper is the carrying value.
18
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 an inactive 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 June 30, 2013 and December 31, 2012.
Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first six months of 2013 and 2012.
Long-term investments balance at beginning of period
Redemptions of principal
Long-term investments balance at end of period
19. 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.
Earnings from continuing operations before income taxes
Income tax expense (benefit)
19
Loss from continuing operations before income taxes
20
The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and six-month periods ended June 30, 2013, compared to the three-month and six-month periods ended June 30, 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.
Adjusted earnings (1)
Earnings (loss) per share
Adjusted earnings per share (1)
Production (MBoe/d)
Realized price per Boe
Operating margin per Boe (2)
Operating cash flow
Adjusted operating cash flow (1)
Capitalized costs
Shareholder distributions
During the three-month and six-month periods ended June 30, 2013, our adjusted earnings, adjusted earnings per share and operating margin per Boe all increased compared to the 2012 periods. The improved 2013 results were driven primarily by increases in gas prices and oil volumes. These factors also contributed to higher adjusted operating cash flow, which when combined with a reduction in capitalized costs, caused our cash flow deficit to narrow considerably in 2013.
During the first six months of 2013, we recognized noncash asset impairments totaling $2.0 billion ($1.3 billion after tax).
21
Results of Operations
Production, Prices and Revenues
Oil (MBbls/d)
U.S.
Canada
Total
Bitumen (MBbls/d)
Gas (MMcf/d)
NGLs (MBbls/d)
Combined (MBoe/d)
Oil (per Bbl)
Bitumen (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Combined (per Boe)
22
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 June 30, 2013 and 2012.
2012 sales
Change due to volumes
Change due to prices
2013 sales
Upstream sales increased $177 million due to a 16 percent increase in our liquids production, partially offset by a 5 percent decline in our gas production in the second quarter of 2013. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $131 million. Bitumen sales increased $9 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $57 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 $20 million decline in sales.
Production information for our key properties is summarized below:
Permian Basin production increased 30 percent compared to the second quarter of 2012 and 13 percent compared to the first quarter of 2013. Oil production accounted for 60 percent of our 76,000 Boe per day produced in the Permian Basin during the second quarter of 2013. The year-over-year increase in total production was driven by a 32 percent increase in oil production.
Barnett Shale production increased 4 percent compared to the second quarter of 2012 and decreased 1 percent compared to the first quarter of 2013. Although total production decreased in the second quarter of 2013 compared to the first quarter of 2013, liquids production increased 2 percent. Liquids production accounted for 24 percent of our 1.4 Bcfe per day produced in the Barnett Shale during the second quarter of 2013. The year-over-year increase in total production was driven by a 34 percent increase in liquids production.
Cana-Woodford Shale production increased 15 percent compared to the second quarter of 2012 and decreased 5 percent compared to the first quarter of 2013. Liquids production accounted for 39 percent of our 322 MMcfe per day produced in Cana during the second quarter of 2013. The year-over-year increase in total production was driven by a 48 percent increase in liquids production.
Jackfish production increased 4 percent compared to the second quarter of 2012 and decreased 2 percent compared to the first quarter of 2013. Bitumen production accounted for all of our 53,000 Boe per day produced at Jackfish during the second quarter of 2013. In June 2013, our Jackfish 1 project reached payout status. Consequently, our Jackfish 1 production will be burdened with a higher Canadian provincial government royalty rate beginning with June 2013. The higher royalty rate decreases our production net of royalties.
Granite Wash production increased 16 percent compared to the second quarter of 2012 and 33 percent compared to the first quarter of 2013. Liquids production accounted for 52 percent of our 22,000 Boe per day produced in the Granite Wash during the second quarter of 2013.
Mississippian-Woodford Trend production increased 73 percent compared to the first quarter of 2013 to 5,000 Boe per day. Oil production accounted for 61 percent of our total production in the Mississippian-Woodford Trend during the second quarter of 2013.
Rocky Mountain production decreased 6 percent compared to the second quarter of 2012. Although total production was down, oil production increased 27 percent compared to the second quarter of 2012. Liquids production accounted for nearly 32 percent of our 333 MMcfe per day produced in the Rocky Mountains during the second quarter of 2013.
Gulf Coast/East Texas production decreased 11 percent compared to the second quarter of 2012. Liquids production accounted for nearly 25 percent of our 329 MMcfe per day produced in Gulf Coast/East Texas during the second quarter of 2013.
Lloydminster production decreased 12 percent compared to the second quarter of 2012. Oil production accounted for 94 percent of our 30,000 Boe per day produced at Lloydminster during the second quarter of 2013.
23
Upstream sales increased $428 million in the second quarter of 2013 primarily due to a 34 percent increase in our realized price without hedges. Our gas sales were the most significantly impacted with a $383 million increase due to prices. 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 and bitumen sales increased $102 million as a result of 11 percent increase in our realized price without hedges. NGL sales decreased $57 million as a result of a 16 percent decrease in our realized price without hedges. The largest contributor to the lower NGL price was a decrease in the average NGL prices at the Mont Belvieu, Texas hub.
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the six months ended June, 30, 2013 and 2012.
Upstream sales increased $277 million due to a 13 percent increase in our liquids production, partially offset by a 6 percent decline in our gas production in the first six months of 2013. As a result of continued development of our oil properties, primarily in the Permian Basin, oil sales increased $223 million. Bitumen sales increased $43 million due to development of our Jackfish thermal heavy oil projects in Canada. Additionally, our NGL sales increased $78 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 $67 million decline in sales.
Upstream sales increased $217 million during the first six months of 2013 due to a 14 percent increase in our realized price without hedges. Our gas sales increased $492 million due to prices. 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. Our liquids sales decreased $275 million due to lower realized prices without hedges. The largest contributors to the lower liquids prices were a decrease in the average NYMEX West Texas Intermediate index price, wider bitumen differentials and lower NGL prices at the Mont Belvieu, Texas hub.
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.
Gas derivatives
Oil derivatives
NGL derivatives
Unrealized gains (losses) on fair value changes:
Total unrealized gains (losses) on fair value changes
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Realized price without hedges
Cash settlements of hedges (1)
Realized price, including cash settlements
Cash settlements of hedges
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 generated a net gain of $366 million and $665 million in the second quarter of 2013 and 2012, respectively. Including the cash settlements discussed above, our commodity derivatives generated a net gain of $46 million and $810 million in the first six months of 2013 and 2012, respectively.
Marketing and Midstream Revenues and Operating Costs and Expenses
Revenues
Operating costs and expenses
Operating profit
During the second quarter and first six months of 2013, marketing and midstream operating profit increased $53 million and $66 million, respectively, primarily due to higher natural gas prices and higher utilization at the fractionator facility in Mont Belvieu.
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Lease Operating Expenses (“LOE”)
LOE ($ in millions):
LOE per Boe:
LOE increased $0.50 per Boe and $0.42 per Boe during the second quarter and first six months of 2013, respectively. The largest contributor to the higher unit cost is related to our liquids production growth, particularly in the Permian Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A ($ in millions):
Oil & gas properties
Other properties
DD&A per Boe:
DD&A from our oil and gas properties decreased in both 2013 periods largely as a result of the asset impairment charges recognized in 2012 and 2013. DD&A from our other properties increased in both 2013 periods largely from the construction of our new headquarters in Oklahoma City and natural gas pipeline development in the Cana-Woodford Shale.
General and Administrative Expenses (“G&A”)
Gross G&A
Capitalized G&A
Reimbursed G&A
Net G&A
Net G&A per Boe
Net G&A and net G&A per Boe decreased in both 2013 periods largely due to lower administrative expenses, as well as higher reimbursements due to increased well counts and reimbursement rates.
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Taxes Other Than Income Taxes
Production
Ad valorem and other
Percentage of oil, gas and NGL revenue:
Taxes other than income taxes as a percentage of oil, gas and NGL revenue decreased during the second quarter of 2013, primarily due to ad valorem and other taxes that do not change in direct correlation with oil, gas and NGL revenues. Taxes other than income taxes as a percentage of oil, gas and NGL revenue increased during the first six months of 2013, 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
Interest on outstanding debt
Capitalized interest
Interest expense increased in both 2013 periods primarily due to higher average 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.
Restructuring Costs
In the six months ended June 30, 2013, we incurred $46 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $25 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 $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.
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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 11 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
If pricing conditions decline from June 30, 2013, we could incur additional full cost ceiling impairments related to our oil and gas property and equipment.
Income Taxes
In the second quarter of 2013, we repatriated to the United States $2.0 billion of cash from our foreign subsidiaries. In conjunction with the repatriation, we recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.
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Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in our cash and short-term investments.
Operating cash flow – continuing operations
Debt activity, net
Divestitures of property and equipment
Net change in cash and short-term investments
Cash and short-term investments at end of period
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities (“operating cash flow”) was our primary source of capital in the first six months of 2013. Our operating cash flow was comparable to the first six months of 2012.
During the first six months of 2013 and 2012, our operating cash flow funded approximately 70 percent and 60 percent, respectively, 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.
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
Development
Exploration
Subtotal
Capitalized G&A and interest
Midstream
Corporate and other
Total capital expenditures
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 $3.1 billion and $3.9 billion in the first six months of 2013 and 2012, respectively. The 21% decline in exploration and development capital spending in the first six months of 2013 was primarily due to a decline in new venture acreage acquisitions and utilization of the drilling carries in 2013 from our Sinopec and Sumitomo joint venture arrangements.
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 plants in the Barnett and Cana-Woodford Shales and the Access Pipeline in Canada.
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Debt Activity, Net
During the first six months of 2013, we repatriated $2.0 billion of foreign earnings to the U.S. and repaid outstanding commercial paper borrowings. The repayment resulted in a net repayment of $1.5 billion for the first six months of 2013. During the first six months of 2012, we received $2.5 billion from the issuance of long-term debt, the proceeds of which were primarily used to repay outstanding commercial paper and credit facility borrowings. We also utilized short-term borrowings of $967 million to fund capital expenditures in excess of our operating cash flow.
The following table summarizes our common stock dividends (amounts in millions) during the first six months of 2013 and 2012. In the second quarter of 2013, we increased our quarterly dividend to $0.22 per share.
Divestitures of Property and Equipment
During the second quarter of 2012, we closed a joint venture transaction with Sinopec. Sinopec paid approximately $900 million in cash and received a 33.3% interest in five of our new ventures exploration plays in the U.S. Sinopec is also funding approximately $1.6 billion of our share of exploration, development and drilling costs associated with these plays.
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 June 30, 2013 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
Credit Availability
As of June 30, 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 June 30, 2013, we had $1.7 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 June 30, 2013, we were in compliance with this covenant with a debt-to-capitalization ratio of 22.8 percent.
At June 30, 2013, we held approximately $4.2 billion of cash and short-term investments. Included in this total was $4.0 billion of cash and short-term investments held by our foreign subsidiaries. While we are using a portion of our foreign cash to invest in the development and growth of our Canadian business, we did repatriate $2.0 billion to the U.S. in the second quarter of 2013 at a reduced income tax rate. Additionally, as we progress through 2013 and gain additional clarity on our current and expected tax attributes, we believe we could repatriate additional amounts of cash to the U.S. in a tax-efficient manner in the second half of 2013 or in 2014. We anticipate using any repatriated funds to reduce outstanding debt.
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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.
Net earnings (loss) (GAAP)
Adjustments (net of taxes):
Interest rate and other financial instruments
Adjusted earnings (Non-GAAP)
Earnings (loss) per share (GAAP)
Adjusted earnings per share (Non-GAAP)
Adjusted Cash Flow
Below is a reconciliation of our adjusted operating cash flow to its comparable GAAP measure.
Operating cash flow (GAAP)
Changes in assets and liabilities
Operating cash flow before balance sheet changes (Non-GAAP)
Current taxes on cash repatriation
Adjusted operating cash flow (Non-GAAP)
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Commodity Price Risk
We have commodity derivatives that pertain to a portion of our production for the last six months of 2013, as well as 2014 and 2015. The key terms to our open oil, gas and NGL derivative financial instruments as of June 30, 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 June 30, 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:
Gain (loss):
Interest Rate Risk
At June 30, 2013, we had total debt outstanding of $10.2 billion. Of this amount, $8.5 billion bears fixed interest rates averaging 5.4 percent. The remaining $1.7 billion of commercial paper borrowings bears interest rates that averaged 0.36 percent.
As of June 30, 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 June 30, 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 June 30, 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 based in Canadian dollars. Additionally, at June 30, 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. Additionally, the increase or decrease in the value of the forward contracts is offset by intercompany loans which increase or decrease from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of June 30, 2013, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.
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.
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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 June 30, 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.
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
There have been no material changes to the information included in Item 3. “Legal Proceedings” in our 2012 Annual Report on Form 10-K.
There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2012 Annual Report on Form 10-K.
The following table provides information regarding purchases of our common stock that were made by us during the second quarter of 2013.
April 1 – April 30
May 1 – May 31
June 1 – June 30
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 4,100 shares of our common stock in the second 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.
Not applicable.
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(a) Exhibits required by Item 601 of Regulation S-K are as follows:
ExhibitNumber
Description
Devon Energy Corporation Non - Qualified Deferred Compensation Plan (as Amended and Restated Effective January 1, 2013).
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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.
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INDEX TO EXHIBITS
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