UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended June 30, 2012
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 address: 20 North Broadway, Oklahoma City, Oklahoma 73102-8260
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, 2012, 404.5 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, 2011 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
(In millions, except
per share amounts)
Revenues:
Oil, gas and NGL sales
Oil, gas and NGL derivatives
Marketing and midstream revenues
Total revenue
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
Other, net
Total expenses and other, net
Earnings from continuing operations before income taxes
Current income tax expense (benefit)
Deferred income tax expense
Earnings from continuing operations
Earnings (loss) from discontinued operations, net of tax
Net earnings
Basic net earnings per share:
Basic earnings from continuing operations per share
Basic earnings (loss) from discontinued operations per share
Basic net earnings per share
Diluted net earnings per share:
Diluted earnings from continuing operations per share
Diluted earnings (loss) from discontinued operations per share
Diluted net earnings per share
Comprehensive earnings:
Other comprehensive earnings, net of tax:
Foreign currency translation
Pension and postretirement plans
Other comprehensive earnings, net of tax
Comprehensive earnings
See accompanying notes to consolidated financial statements.
3
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Loss (earnings) from discontinued operations, net of tax
Adjustments to reconcile earnings 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
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
Purchases of short-term investments
Redemptions of short-term investments
Proceeds from property and equipment divestitures
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 (repayments) borrowings
Credit facility borrowings
Credit facility repayments
Proceeds from stock option exercises
Repurchases of common stock
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 increase 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
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 404.5 million and 404.1 million shares in 2012 and 2011, 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
Accumulated
Comprehensive
Total
Stockholders’
Six Months Ended June 30, 2012:
Balance as of December 31, 2011
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, 2012
Six Months Ended June 30, 2011:
Balance as of December 31, 2010
Balance as of June 30, 2011
6
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 2011 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 financial position as of June 30, 2012 and Devon’s results of operations and cash flows for the three-month and six-month periods ended June 30, 2012 and 2011.
Accounts Payable
Included in accounts payable at June 30, 2012, are liabilities of $99 million representing the amount by which checks issued, but not presented to Devon’s banks for collection, exceed balances in applicable bank accounts. Changes in these liabilities are reflected in cash flows from financing activities.
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 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, 2012, Devon holds $107 million 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.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Commodity Derivatives
As of June 30, 2012, 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 2012
Q1-Q4 2013
Q1-Q4 2014
As of June 30, 2012, Devon had the following open natural gas derivative positions. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index.
Interest Rate Derivatives
As of June 30, 2012, Devon had the following open interest rate derivative positions:
Notional
$ 100
750
$ 850
Foreign Exchange Derivatives
As of June 30, 2012, Devon had the following open foreign exchange rate derivative position:
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.
8
Cash settlements:
Commodity derivatives
Interest rate derivatives
Foreign currency derivatives
Total cash settlements
Unrealized gains (losses):
Total unrealized gains
Net gain recognized on comprehensive statements of earnings
The following table presents the derivative fair values included in the accompanying balance sheets.
Balance Sheet Caption
Asset derivatives:
Total asset derivatives
Liability derivatives:
Foreign exchange derivatives
Total liability derivatives
3. Restructuring Costs
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of June 30, 2012, Devon had divested all of its U.S. Offshore and International assets. Since inception of the plan, Devon has incurred $202 million of restructuring costs associated with these divestitures.
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs related to Devon’s discontinued operations totaled $(8) million and $(2) million in the second quarter and first six months of June 30, 2011. These costs primarily related to cash severance and share-based awards and are not included in the schedule below. There were no costs related to discontinued operations in the six months ended June 30, 2012.
Lease obligations
Asset impairments
9
The schedule below summarizes Devon’s restructuring liabilities. Devon’s restructuring liabilities for cash severance related to its discontinued operations totaled $10 million at June 30, 2011 and are not included in the schedule below.
Lease obligations settled
Cash severance settled
4. Other, net
The components of other, net in the accompanying comprehensive statements of earnings include the following:
Accretion of asset retirement obligations
Interest rate swaps – cash settlements
Interest rate swaps – unrealized fair value changes
Interest income
5. Earnings Per Share
The following table reconciles earnings from continuing operations and common shares outstanding used in the calculations of basic and diluted earnings per share.
Three Months Ended June 30, 2012:
Attributable to participating securities
Basic earnings per share
Dilutive effect of potential common shares issuable
Diluted earnings per share
Three Months Ended June 30, 2011:
10
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, 2012, 8.9 million shares and 6.7 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2011, 3.1 million shares were excluded from the diluted earnings per share calculations.
6. 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 expense
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
Ending accumulated pension and postretirement benefits
Accumulated other comprehensive earnings, net of tax
11
7. Supplemental Information to Statements of Cash Flows
Net change in working capital:
Decrease (increase) in accounts receivable
Increase in other current assets
Increase in accounts payable
(Decrease) increase in revenues and royalties payable
Decrease in other current liabilities
Supplementary cash flow data – total operations:
Interest paid (net of capitalized interest)
Income taxes paid (received)
8. Short-Term Investments
The components of short-term investments include the following:
Canadian treasury, agency and provincial securities
U.S. treasuries
9. Accounts Receivable
The components of accounts receivable include the following:
Joint interest billings
Gross accounts receivable
Allowance for doubtful accounts
Net accounts receivable
12
10. Other Current Assets
The components of other current assets include the following:
Derivative financial instruments
Inventories
Income taxes receivable
Current assets held for sale
11. Property and Equipment
In April 2012, Devon closed its joint venture transaction with Sinopec International Petroleum Exploration & Production Corporation. Pursuant to the agreement, Sinopec paid approximately $900 million in cash and received a 33.3% interest in five of Devon’s new ventures exploration plays in the U.S. at closing of the transaction. Additionally, Sinopec is required to fund approximately $1.6 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon recognized the cash proceeds received at closing as a reduction to U.S. oil and gas property and equipment. No gain or loss was recognized.
12. Other Current Liabilities
The components of other current liabilities include the following:
Deferred income taxes payable
Accrued interest
13. Debt
Long-Term Debt
In May 2012, Devon issued $2.5 billion of senior notes that are unsecured and unsubordinated obligations of Devon. Devon used the net proceeds to repay outstanding commercial paper and credit facility borrowings. The schedule below summarizes the key terms of these notes ($ in millions).
1.875% due May 15, 2017
3.25% due May 15, 2022
4.75% due May 15, 2042
Discount and issuance costs
Net proceeds
Commercial Paper
As of June 30, 2012, Devon had $2.1 billion of outstanding commercial paper at an average rate of 0.40 percent.
13
Credit Lines
On April 7, 2012, $0.46 billion of Devon’s Senior Credit Facility matured and was not extended. After the maturity, Devon maintains a $2.19 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”). As of June 30, 2012, 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 less than 65 percent. As of June 30, 2012, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.8 percent.
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
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
During the first quarter of 2012, Devon recognized revisions to its asset retirement obligations totaling $399 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.
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
Net actuarial loss
Net periodic benefit cost
16. Stockholders’ Equity
In the second quarter of 2012, Devon’s stockholders adopted the 2012 amendment to the 2009 Long-Term Incentive Plan (“2009 Plan Amendment”), which expires June 2, 2019. The 2009 Plan Amendment increases the number of shares authorized for issuance from 21.5 million shares to 47 million shares. To calculate shares issued under the 2009 Long-Term Incentive Plan subsequent to the 2009 Plan Amendment, options and stock appreciation rights represent one share and other awards represent 2.38 shares.
14
Dividends
Devon paid common stock dividends of $162 million and $140 million in the first six months of 2012 and 2011, respectively. The quarterly cash dividend was $0.16 per share in the first quarter of 2011. Devon increased the dividend rate to $0.17 per share in the second quarter of 2011 and further increased the dividend rate to $0.20 per share in the first quarter of 2012.
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 agreements 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 the states of Oklahoma and 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. Both Rees-Jones and Devon are appealing the judgment. If the appeal is unsuccessful, Devon can and will seek full payment of the judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not expect to have any net exposure as a result of the judgment. However, because Devon does not have a legal right of set off with respect to the judgment, Devon has recorded in the accompanying June 30, 2012 and December 31, 2011, balance sheets both 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.
15
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.
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, 2012 and December 31, 2011. Therefore, such financial assets and liabilities are not presented in the following tables.
June 30, 2012 assets (liabilities):
Cash equivalents
Long-term investments
Debt
December 31, 2011 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 is based upon quotes from brokers, which approximate the carrying value.
Commodity, interest rate and foreign exchange derivatives — The fair values of commodity and interest rate derivatives are estimated using internal discounted cash flow calculations based upon forward curves and quotes obtained from brokers for contracts with similar terms or quotes 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.
16
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 the AAA credit rating of the securities, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, the collection of all accrued interest to date and continued receipts of principal at par. 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, 2012 and December 31, 2011.
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 rely on unobservable inputs to estimate the fair value of its promissory note. The fair value of this debt is estimated using internal discounted cash flow calculations based upon estimated future payment schedules and a 3.125% interest rate.
Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first six months of 2012 and 2011.
Long-term investments balance at beginning of period
Redemptions of principal
Long-term investments balance at end of period
Debt balance at beginning of period
Foreign exchange translation adjustment
Accretion of promissory note
Debt balance at end of period
19. Discontinued Operations
In March 2012, Devon received $71 million upon closing the divestiture of its operations in Angola, which completed Devon’s offshore divestiture program that was announced in November 2009. In aggregate, Devon’s U.S. and International offshore divestitures generated total proceeds of $10.1 billion, or approximately $8 billion after-tax, assuming repatriation of a substantial portion of the foreign proceeds under current U.S. tax law.
Revenues related to Devon’s discontinued operations totaled $43 million in the six months ended June 30, 2011. Devon did not have revenues related to its discontinued operations during the second quarter of 2011 or the first six months of 2012. Earnings (loss) from discontinued operations before income taxes totaled $(16) million in the six months ended June 30, 2012 and $2.6 billion for the second quarter and first six months of 2011, respectively. Devon did not have any earnings in the second quarter of 2012. Earnings (loss) from discontinued operations in 2012 and 2011 were primarily due to Devon’s International divestiture transactions.
17
The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations at December 31, 2011. Devon did not have assets or liabilities held for sale at June 30, 2012.
20. Segment Information
Devon manages its operations through distinct operating segments, or divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. divisions into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian division 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.
Income tax expense (benefit)
Capital expenditures (2)
18
Total continuing assets (1)
21. Subsequent Event
In August 2012, Devon announced a transaction with Sumitomo Corporation that Devon expects to close in the third quarter of 2012. Under the agreement, Sumitomo will pay $1.365 billion, including $340 million at closing and $1.025 billion toward Devon’s share of future drilling costs, and will receive a 30% interest in the Cline and Midland-Wolfcamp shale plays.
19
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, 2012, compared to the three-month and six-month periods ended June 30, 2011, and in our financial condition and liquidity since December 31, 2011. For information regarding our critical accounting policies and estimates, see our 2011 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Overview of 2012 Results
During the second quarter and first six months of 2012, our continuing operations generated net earnings of $477 million, or $1.18 per diluted share, and $891 million, or $2.20 per diluted share, for the respective periods. This compares to net earnings of $184 million, or $0.43 per diluted share, and $573 million, or $1.34 per diluted share for the second quarter and first six months of 2011, respectively. Key measures of our financial performance are summarized below:
Total production rose by 3% and 6% during the second quarter and first six months of 2012, respectively. Our production growth was driven by oil production, which climbed 26% to 149 MBbls per day in the second quarter of 2012.
The combined realized price without hedges for oil, gas and NGLs decreased 29% to $26.18 per Boe and 19% to $28.28 per Boe in the second quarter and first six months of 2012, respectively.
Oil, gas and NGL derivatives generated a net gain of $665 million and $810 million in the second quarter and first six months of 2012, respectively, and generated a net gain of $416 million and $248 million in the second quarter and first six months of 2011, respectively. Included in these amounts were cash receipts of $267 million and $425 million in the second quarter and first six months of 2012, respectively, and $59 million and $145 million in the second quarter and first six months of 2011, respectively.
Marketing and midstream operating profit decreased 54% to $68 million and 33% to $180 million in the second quarter and first six months of 2012, respectively.
Per unit operating costs increased 10% to $8.30 per Boe and 9% to $8.23 per Boe in the second quarter and first six months of 2012, respectively.
Operating cash flow from continuing operations decreased 14% to $2.4 billion.
Capital spending totaled approximately $4.3 billion in the first six months of 2012.
Second Quarter Operational Developments
Permian Basin oil production increased 24 percent over the second quarter of 2011. Oil production accounted for nearly 60 percent of the 59,000 Boe per day produced in the Permian Basin during the second quarter.
We brought 19 Bone Spring wells online in the second quarter. Initial daily production averaged 680 Boe per day.
Net production from our Jackfish oil sands projects averaged a record 51,000 barrels per day in the second quarter. This represents a 63 percent increase in oil production over the year-ago quarter. Construction of our third Jackfish oil sands project is now approximately 40 percent complete. Plant startup is targeted for late 2014.
We filed a regulatory application in June for the first phase of our Pike, an oil sands project with gross production capacity of 105,000 barrels per day. Pike is located immediately adjacent to the company’s highly successful Jackfish projects.
In April, we closed our $2.5 billion joint venture agreement with Sinopec. The transaction included an approximate $900 million cash payment at closing, recovering significantly more than 100 percent of our initial land and exploration costs. The remaining $1.6 billion drilling-carry will fund 80 percent of the joint venture’s capital requirements over the next few years.
We continued to increase our exposure in the Mississippian oil play by adding 400,000 net acres in Oklahoma. In total, we now have 545,000 net acres in this emerging light-oil resource play.
We brought six Granite Wash wells online in the second quarter. Initial production from these wells averaged 1,270 Boe per day.
Net production from the Cana-Woodford Shale averaged 280 million cubic feet of natural gas equivalent per day in the second quarter of 2012. Liquids production increased 59 percent year-over-year, accounting for 30 percent of total Cana-Woodford production.
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Results of Operations
Production, Prices and Revenues
Oil (MBbls/d)
U.S.
Canada
Gas (MMcf/d)
NGLs (MBbls/d)
Combined (MBoe/d) (2)
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Combined (per Boe)
21
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, 2012 and 2011.
2011 sales
Changes due to volumes
Changes due to prices
2012 sales
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, 2012 and 2011.
Oil Sales
A 26 percent increase in production during the second quarter and first six months of 2012 caused oil sales to increase by $229 million and $428 million, respectively. The increases were primarily due to continued development of our Jackfish thermal heavy oil projects and Permian Basin properties.
Oil sales decreased $211 million and $139 million during the second quarter and first six months of 2012, respectively, as a result of 19 percent and 7 percent decreases, respectively, in our realized price without hedges. The largest contributor to the decreases in each period to our realized price was the widening differential to the NYMEX West Texas Intermediate index price attributable to our Canadian oil production.
Gas Sales
Gas sales decreased $478 million and $785 million in the second quarter and first six months of 2012, respectively, as a result of 54 percent and 45 percent decreases, respectively, in our realized price without hedges. These decreases were largely due to the broad deterioration of gas prices in the North American market.
Gas sales decreased $25 million during the second quarter due to a 3 percent decrease in production and increased $17 million during the first six months of 2012 as a result of a slight increase in production. Our gas production has remained somewhat steady as a result of the continued development activities in the liquids-rich gas portions of our Barnett and Cana-Woodford Shales. Production gains from development in these liquids-rich regions were partially offset by natural declines in our other operating areas, particularly those that produce dry gas.
NGL Sales
NGL sales decreased $100 million and $125 million in the second quarter and first six months of 2012, respectively, as a result of 26 percent and 16 percent decreases, respectively, in our realized price without hedges. The lower prices were largely due to decreases in NGL prices at the Mont Belvieu, Texas hub price.
NGL sales increased $2 million and $76 million in the second quarter and first six months of 2012, respectively, as a result of production increases in each period. The increases in production were primarily due to continued drilling in the liquids-rich gas portions of the Barnett Shale, Cana-Woodford Shale and Granite Wash.
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Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and unrealized gains and losses that are recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.
Gas derivatives
Oil derivatives
NGL derivatives
Unrealized gains (losses) on fair value changes:
Total unrealized gains on fair value changes
Realized price without hedges
Cash settlements of hedges
Realized price, including cash settlements
A summary of our outstanding commodity derivatives is included 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 these various instruments.
In addition to cash settlements, we also recognize unrealized changes in the fair values of our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain of $665 million and $416 million in the second quarter of 2012 and 2011, respectively. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain of $810 million and $248 million in the first six months of 2012 and 2011, respectively.
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Marketing and Midstream Revenues and Operating Costs and Expenses
Marketing and midstream:
Revenues
Operating costs and expenses
Operating profit
During the second quarter and first six months of 2012, marketing and midstream operating profit decreased $80 million and $90 million, respectively, primarily due to lower gas and NGL prices.
Lease Operating Expenses (“LOE”)
LOE ($ in millions):
LOE per Boe:
LOE increased $0.75 per Boe and $0.71 per Boe during the second quarter and first six months of 2012, respectively. The largest contributor to the higher unit cost is related to our liquids production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We also experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A ($ in millions):
Oil & gas properties
Other properties
DD&A per Boe:
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Oil and gas property DD&A increased during the second quarter and first six months of 2012 largely due to increases in the DD&A rates. The largest contributor to the higher rates were our drilling and development activities subsequent to the end of the second quarter of 2011.
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 the present value of estimated future net cash flows from proved oil and gas reserves, discounted 10 percent, 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. If natural gas prices remain depressed, we expect to incur full-cost ceiling write-downs, or additional DD&A, related to our U.S. oil and gas properties in the third quarter of 2012.
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 increased during 2012 largely due to higher employee compensation and benefits. Employee costs increased primarily from an expansion of our workforce as part of growing production operations at certain of our key areas, including Jackfish, the Permian and the Cana-Woodford shale.
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 our oil, gas and NGL revenues increased in both 2012 periods primarily due to ad valorem and other taxes, which do not change in direct correlation with oil, gas and NGL revenues.
Interest Expense
Interest based on debt outstanding
Capitalized interest
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Interest based on debt outstanding increased during the second quarter and first six months of 2012 as a result of additional debt borrowings. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.
Income Taxes
The following table presents our total income tax expense and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.
Total income tax expense (in millions)
U.S. statutory income tax rate
State income taxes
Taxation on Canadian operations
Assumed repatriations
Effective income tax expense rate
Earnings (Loss) From Discontinued Operations
Operating earnings
Gain (loss) on sale of oil and gas properties
Earnings (loss) before income taxes
Earnings (loss) from discontinued operations
Earnings decreased in 2012 primarily as a result of the $2.5 billion gain ($2.5 billion after-tax) recognized from the divestiture of our Brazil operations in the second quarter of 2011.
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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 cash equivalents.
Operating cash flow – continuing operations
Debt activity, net
Divestitures of property and equipment
Short-term investment activity, net
Common stock repurchases and dividends
Short-term investments at end of period
Operating Cash Flow – Continuing Operations
Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in the first six months of 2012. Our operating cash flow decreased approximately 14 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth.
In 2011, we completed our offshore divestiture program that was announced in November 2009. This program generated approximately $8 billion in after-tax proceeds, which provided us with substantial liquidity to invest in our North America property base. During the first six months of 2012 and 2011, our operating cash flow funded approximately 60 percent and 75 percent, respectively, of our cash payments for capital expenditures. Leveraging our liquidity, we largely used debt to fund the remainder of our cash-based capital expenditures. This cash flow deficit was largely expected as we have allocated approximately 25% of our 2012 capital expenditure budget to exploratory projects and leasehold acquisitions that are not yet generating production revenues.
Debt Activity, Net
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.
During the first six months of 2011, we utilized commercial paper borrowings of $2.3 billion to fund capital expenditures and common share repurchases.
Divestitures of Property and Equipment
During the second quarter of 2012, we closed our 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 required to fund approximately $1.6 billion of our share of future exploration, development and drilling costs associated with these plays. In the first quarter of 2012, we received $71 million from the divestiture of our Angola operations.
During the second quarter of 2011, we completed the divestiture of our operations in Brazil, generating $3.3 billion in net proceeds.
Short-term Investments
During the first six months of 2012 and 2011, we had net short-term investment redemptions totaling $0.6 billion and net purchases totaling $3.2 billion, respectively. The 2012 redemptions were used to supplement our operating cash flow to fund our capital expenditures. The 2011 activity was primarily related to our investment of a portion of the International offshore divestiture proceeds into marketable securities.
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Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
Midstream
Total continuing operations
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 $3.9 billion and $3.3 billion in the first six months of 2012 and 2011, respectively. The 17% growth in exploration and development capital spending in the first six months of 2012 was primarily due to increased new ventures exploratory activity and unproved leasehold acquisitions.
Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil transportation facilities. Our midstream capital expenditures are largely impacted by oil and gas drilling activities.
Common Stock Repurchases and Dividends
In connection with our offshore divestitures noted above, we conducted a $3.5 billion share repurchase program, which we completed in the fourth quarter of 2011. Since the second quarter of 2011, we have increased our quarterly dividend rate 18%.
The following table summarizes our repurchases and our common stock dividends (amounts and shares in millions) during the first six months of 2012 and 2011.
Repurchases
Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow 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 2011 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 our 2012 production. The key terms to our oil, gas and NGL derivative financial instruments as of June 30, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
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Credit Availability
As of July 18, 2012, we had $2.1 billion of available capacity under our syndicated, unsecured Senior Credit Facility and $2.6 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, of no more than 65 percent. As of June 30, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 23.8 percent.
Although we ended the second quarter of 2012 with approximately $7.0 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures that are held by certain of our foreign subsidiaries. We do not currently expect to repatriate such amounts to the U.S. If we were to repatriate a portion or all of the cash and short-term investments held by these foreign subsidiaries, we would be required to accrue and pay current income taxes in accordance with current U.S. tax law. With these proceeds remaining outside of the U.S., we expect to continue using commercial paper and credit facility borrowings in the U.S. to supplement our U.S. operating cash flow. We do not expect near-term increases in such borrowings will have a material effect on our overall liquidity or financial condition.
We previously disclosed that we expected our 2012 capital expenditures to range from $6.2 billion to $6.8 billion. In the first half of 2012, we expanded our new ventures exploration activities, targeting oil and liquids-rich opportunities. As a result, we increased our total estimated 2012 capital expenditures by $1.0 billion.
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 six months of 2012, as well as 2013 and 2014. The key terms to all our oil, gas and NGL derivative financial instruments as of June 30, 2012 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, 2012, 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, 2012, we had total debt outstanding of $10.6 billion. Our long-term debt of $8.5 billion bears fixed interest rates averaging 5.4 percent. The remaining $2.1 billion of commercial paper borrowings bears interest at fixed rates which averaged 0.40 percent. Such borrowings typically have maturity rates between 1 and 90 days.
As of June 30, 2012, 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, 2012.
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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, 2012 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 June 30, 2012, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash. 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 June 30, 2012, 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.
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, 2012, 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
On April 1, 2012, we implemented SAP, a company-wide enterprise resource planning software system. SAP replaced certain of our accounting and other systems that are used to record and report our financial results and associated disclosures. In conjunction with the SAP implementation, we modified the design, operation and documentation of our internal controls over financial reporting.
Except as described above, there were no other 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 2011 Annual Report on Form 10-K.
There have been no material changes to the information included in Item 1A. “Risk Factors” in our 2011 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 2012.
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 6,600 shares of our common stock in the second quarter of 2012, 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.
None.
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(a) Exhibits required by Item 601 of Regulation S-K are as follows:
ExhibitNumber
Description
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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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