UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
For the quarterly period ended September 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 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 October 24, 2012, 405 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 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 (benefit)
Deferred income tax expense (benefit)
Earnings (loss) from continuing operations
Earnings (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 earnings (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 earnings (loss) from discontinued operations per share
Diluted net earnings (loss) per share
Comprehensive earnings (loss):
Other comprehensive earnings (loss), net of tax:
Foreign currency translation
Pension and postretirement plans
Other comprehensive earnings (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:
Net earnings
(Earnings) loss from discontinued operations, net of tax
Adjustments to reconcile earnings from continuing operations to net cash from operating activities:
Deferred income tax expense
Unrealized change in fair value of financial instruments
Other noncash charges
Net decrease (increase) in working capital
Decrease (increase) 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
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 borrowings (repayments)
Debt repayments
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 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
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 405 million and 404 million shares in 2012 and 2011, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive earnings
Total stockholders’ equity
Commitments and contingencies (Note 18)
Total liabilities and stockholders’ equity
5
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Nine Months Ended September 30, 2012:
Balance as of December 31, 2011
Other comprehensive earnings, net of tax
Stock option exercises
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Share-based compensation tax benefits
Balance as of September 30, 2012
Nine Months Ended September 30, 2011:
Balance as of December 31, 2010
Other comprehensive loss, net of tax
Balance as of September 30, 2011
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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 September 30, 2012 and Devon’s results of operations and cash flows for the three-month and nine-month periods ended September 30, 2012 and 2011.
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 September 30, 2012, Devon held $49 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 September 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
Q4 2012
Q1-Q4 2 013
Q1-Q4 2014
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
Basis Swaps
Index
As of September 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.
Q1-Q4 2013
Interest Rate Derivatives
As of September 30, 2012, Devon had the following open interest rate derivative positions:
Notional
Variable
Rate Paid
Expiration
$ 750
Foreign Currency Derivatives
As of September 30, 2012, Devon had the following open foreign currency rate derivative positions:
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
8
Unrealized gains (losses):
Total unrealized gains (losses)
Net gain (loss) 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:
Total liability derivatives
3. Restructuring Costs
Divestiture of Offshore Assets
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of September 30, 2012, Devon had divested all of its U.S. Offshore and International assets and incurred $202 million of restructuring costs associated with the divestitures.
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings. Restructuring costs related to Devon’s discontinued operations totaled $(2) million in the first nine months ended September 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 nine months ended September 30, 2012.
Lease obligations
9
The schedule below summarizes Devon’s restructuring liabilities. Devon’s restructuring liabilities for cash severance related to its discontinued operations totaled $2 million at September 30, 2011 and are not included in the schedule below.
Lease obligations settled
Cash severance settled
Consolidation of U.S. Operations
In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the company’s corporate headquarters in Oklahoma City. As a result, Devon will close its office in Houston and transfer operational responsibilities for assets in South Texas, East Texas and Louisiana to Oklahoma City. Devon expects to relocate a number of employees from Houston to Oklahoma City. This initiative is expected to be substantially complete by the end of the first quarter 2013.
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 (gain)
Interest income
10
5. Earnings 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 September 30, 2012:
Loss from continuing operations
Attributable to participating securities
Basic and diluted loss per share
Three Months Ended September 30, 2011:
Earnings from continuing operations
Basic earnings per share
Dilutive effect of potential common shares issuable
Diluted earnings per share
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 nine-month periods ended September 30, 2012, 9.0 million shares and 8.9 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and nine-month periods ended September 30, 2011, 5.3 million shares and 3.1 million shares, respectively, 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 benefit (expense)
Ending accumulated foreign currency translation
11
Pension and postretirement benefit plans:
Beginning accumulated pension and postretirement benefits
Recognition of net actuarial loss and prior service cost in earnings
Income tax expense
Ending accumulated pension and postretirement benefits
Accumulated other comprehensive earnings, net of tax
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
Increase (decrease) 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
12
9. Accounts Receivable
The components of accounts receivable include the following:
Joint interest billings
Gross accounts receivable
Allowance for doubtful accounts
Net accounts receivable
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
Sinopec Transaction
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.
Sumitomo Transaction
In September 2012, Devon closed its joint venture transaction with Sumitomo Corporation. At closing, Sumitomo paid approximately $400 million in cash and received a 30% interest in the Cline and Midland-Wolfcamp shale plays in Texas. Additionally, Sumitomo is required to fund approximately $1.0 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.
13
Asset Impairments
In the third quarter of 2012, Devon recognized asset impairments related to its U.S. oil and gas property and equipment and its U.S. midstream assets as presented below.
U.S. oil and gas assets
Midstream assets
Total asset impairments
U.S. Oil and Gas Impairment
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 U.S. oil and gas impairment resulted primarily from a decline in the U.S. full cost ceiling. The lower ceiling value resulted primarily from decreases in the 12-month average trailing prices for natural gas and NGLs, which have reduced proved reserve values.
Additionally, if natural gas and NGL prices remain depressed, Devon may incur a full cost ceiling impairment related to its oil and gas property and equipment in the fourth quarter of 2012.
Midstream Impairment
Due to declining natural gas production resulting from low natural gas and NGL prices, Devon determined that the carrying amounts of certain of its midstream facilities located in south and east Texas were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models. The fair value of Devon’s midstream assets is considered a Level 3 fair value measurement.
12. Goodwill
During the first nine months of 2012, Devon’s Canadian goodwill increased $101 million entirely due to foreign currency translation.
13. Accounts Payable
Included in accounts payable at September 30, 2012, are liabilities of $51 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.
14
14. 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 September 30, 2012, Devon had $2.8 billion of outstanding commercial paper at an average rate of 0.37 percent.
Credit Lines
Devon previously maintained a $2.19 billion syndicated, unsecured revolving line of credit. As of September 30, 2012, there were no borrowings under this line of credit. Devon terminated this line of credit and established a new $3.0 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) on October 24, 2012. The Senior Credit Facility will mature on October 24, 2017. However, prior to the maturity date, Devon has the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.
The terminated line of credit and the Senior Credit Facility each contain 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 September 30, 2012, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 24.7 percent.
15. 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 nine months of 2012, Devon recognized revisions to its asset retirement obligations totaling $411 million. The primary factor contributing to this revision was an overall increase in abandonment cost estimates for certain of its production operations facilities.
15
16. 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
17. 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.
Dividends
Devon paid common stock dividends of $242 million and $209 million in the first nine 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.
18. 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 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.
16
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 September 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.
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.
19. 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 September 30, 2012 and December 31, 2011. Therefore, such financial assets and liabilities are not presented in the following tables.
September 30, 2012 assets (liabilities):
Cash equivalents
Long-term investments
Debt
17
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 data from independent third parties, which approximate the carrying value.
Commodity, interest rate and foreign currency derivatives— The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Debt — Devon’s debt instruments do not actively trade in an established market. The fair values of its fixed-rate debt are estimated based on rates available for debt with similar terms and maturity. The fair values of Devon’s variable-rate commercial paper and credit facility borrowings are the carrying values.
Level 3 Fair Value Measurements
Long-term investments — Devon’s long-term investments presented in the tables above consisted entirely of auction rate securities. Due to auction failures and the lack of an active market for Devon’s auction rate securities, quoted market prices for these securities were not available. Therefore, Devon used valuation techniques that rely on unobservable inputs to estimate the fair values of its long-term auction rate securities. These inputs were based on continued receipts of principal at par, the collection of all accrued interest to date, the probability of full repayment of the securities considering the U.S. government guarantees substantially all of the underlying student loans, and the AAA credit rating of the securities. As a result of using these inputs, Devon concluded the estimated fair values of its long-term auction rate securities approximated the par values as of September 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.
18
Included below is a summary of the changes in Devon’s Level 3 fair value measurements during the first nine 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
20. 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 nine months ended September 30, 2011. Devon did not have revenues related to its discontinued operations during the second or third quarter of 2011 or the first nine months of 2012. Earnings (loss) from discontinued operations before income taxes totaled $(16) million in the nine months ended September 30, 2012 and $2.6 billion for the first nine months of 2011, respectively. Devon did not have any earnings in the third quarter of 2012 or 2011. Earnings (loss) from discontinued operations in 2012 and 2011 were primarily due to Devon’s International divestiture transactions.
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 September 30, 2012.
Total liabilities
19
21. 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.
Income tax expense (benefit)
Earnings (loss) earnings from continuing operations
Earnings from continuing operations before income taxes
Capital expenditures (1)
20
Total continuing assets (2)
21
The following discussion and analysis addresses material changes in our results of operations and capital resources and uses for the three-month and nine-month periods ended September 30, 2012, compared to the three-month and nine-month periods ended September 30, 2011, and in our financial condition and liquidity since December 31, 2011 and should be read in conjunction with “Item 1. Consolidated Financial Statements” of this report and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2011 Annual Report on Form 10-K.
Overview of 2012 Results
During the third quarter of 2012, our continuing operations incurred a net loss of $719 million, or $1.80 per diluted share, due to noncash asset impairments and commodity derivative fair value changes. During the first nine months of 2012 our continuing operations generated earnings of $172 million, or $0.42 per diluted share. This compares to net earnings of $1.0 billion, or $2.50 per diluted share, and $1.6 billion, or $3.82 per diluted share for the third quarter and first nine months of 2011, respectively. Key components of our financial performance are summarized below:
Total production rose by 3% and 5% during the third quarter and first nine months of 2012, respectively. Our production growth was driven by oil production, which climbed 14% to 143 MBbls per day in the third quarter of 2012 in spite of the scheduled shut-down for facilities maintenance at our Jackfish 1 oil sands project.
The combined realized price without hedges for oil, gas and NGLs decreased 20% to $27.85 per Boe and 19% to $28.14 per Boe in the third quarter and first nine months of 2012, respectively.
Fair value changes and cash settlements on oil, gas and NGL derivatives resulted in a net loss of $295 million and a net gain of $515 million in the third quarter and first nine months of 2012, respectively, and a net gain of $738 million and $986 million in the third quarter and first nine months of 2011, respectively.
Marketing and midstream operating profit decreased 21% to $109 million and 29% to $289 million in the third quarter and first nine months of 2012, respectively.
LOE increased 5% and 8% to $8.22 per Boe in the third quarter and first nine months of 2012, respectively.
Noncash asset impairments were $1.1 billion in the third quarter of 2012, or $719 million net of income taxes.
Operating cash flow decreased 10% to $3.8 billion for the first nine months of 2012.
Capital spending, net of divestiture proceeds, totaled approximately $4.8 billion in the first nine months of 2012.
Third Quarter Operational Developments
Permian Basin oil production increased 35 percent over the third quarter of 2011. Oil production accounted for nearly 60 percent of our 65,000 Boe per day produced in the Permian during the third quarter. In the Bone Spring and Delaware plays in the Permian Basin, we added 25 new wells to production in the third quarter 2012. Initial 30-day production from these wells averaged 575 Boe per day. Also in the Permian, we brought five Midland-Wolfcamp Shale wells online in the third quarter with initial 30-day production averaging 560 Boe per day.
In September, we closed our $1.4 billion joint venture agreement with Sumitomo covering 650,000 net acres in the Permian Basin. Our two new exploration joint ventures in 2012 have delivered almost $4 billion in value.
In Canada, net production from our Jackfish projects averaged 44,000 barrels per day in the third quarter. This represents a 24 percent increase in oil production over the year-ago quarter. Construction of our third Jackfish oil sands project is now approximately 45 percent complete, with plant startup expected by year-end 2014.
Our third quarter activity in the Mississippian Lime play in Oklahoma was highlighted by the increase in activity to 13 operated rigs. Results from the Mississippian play continue to support our target economics.
We brought seven operated Granite Wash wells online in the third quarter. The average 30-day production rate from these wells was 1,065 Boe per day.
Our Cana-Woodford Shale production averaged 283 MMcf per day in the third quarter 2012. Third-quarter liquids production increased 64 percent compared to the prior-year quarter to 13,000 barrels per day.
Net production in the Barnett Shale totaled 1.4 Bcf per day in the third quarter. Liquids production increased 11 percent compared to the third quarter of 2011 to 51,000 barrels per day.
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Results of Operations
Production, Prices and Revenues
Oil (MBbls/d)
U.S.
Canada
Total
Gas (MMcf/d)
NGLs (MBbls/d)
Combined (MBoe/d) (2)
Oil (per Bbl)
Gas (per Mcf)
NGLs (per Bbl)
Combined (per Boe)
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The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended September 30, 2012 and 2011.
2011 sales
Change due to volumes
Change 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 nine months ended September 30, 2012 and 2011.
Oil Sales
Oil sales increased $114 million and $537 million during the third quarter and first nine months of 2012, respectively, as a result of 14 percent and 22 percent production increases, respectively. The increases were primarily due to continued development of our Permian Basin properties and Jackfish thermal heavy oil projects.
Oil sales decreased $18 million and $152 million during the third quarter and first nine months of 2012, respectively, as a result of 2 percent and 5 percent decreases, respectively, in our realized price without hedges. The largest contributor to the price decreases in each period was the widening differential to the NYMEX West Texas Intermediate index price attributable to our Canadian oil production.
Gas Sales
Gas sales decreased $329 million and $1.1 billion in the third quarter and first nine months of 2012, respectively, as a result of 37 percent and 42 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 $19 million during the third quarter due to a 2 percent decrease in production and decreased $1 million during the first nine months of 2012 as a result of a slight decrease 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 operating areas that produce dry gas.
NGL Sales
NGL sales decreased $156 million and $281 million in the third quarter and first nine months of 2012, respectively, as a result of 37 percent and 23 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.
NGL sales increased $35 million and $111 million in the third quarter and first nine months of 2012, respectively, as a result of 9 percent and 10 percent production increases, respectively. 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 (losses) on fair value changes
Realized price without hedges
Cash settlements of hedges
Realized price, including cash settlements
Cash settlements presented in the tables above represent realized gains or losses related to various commodity 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.
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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 incurred a net loss of $295 million and generated a net gain of $738 million in the third quarter of 2012 and 2011, respectively. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain of $515 million and $986 million in the first nine months of 2012 and 2011, respectively.
Marketing and Midstream Revenues and Operating Costs and Expenses
Marketing and midstream:
Revenues
Operating Costs and expenses
Operating Profit
During the third quarter and first nine months of 2012, marketing and midstream operating profit decreased $29 million and $119 million, respectively, primarily due to lower gas and NGL prices.
Lease Operating Expenses (“LOE”)
LOE ($ in millions):
LOE per Boe:
LOE increased $0.41 per Boe and $0.60 per Boe during the third quarter and first nine months of 2012, respectively. The largest contributor to the higher unit cost is related to our liquids production growth, particularly at our Jackfish thermal heavy oil projects in Canada and in the Permian Basin in the U.S. Such projects generally require a higher cost to produce per unit than our gas projects. We also experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
Depreciation, Depletion and Amortization (“DD&A”)
DD&A ($ in millions):
Oil & gas properties
Other properties
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DD&A per Boe:
Oil and gas property DD&A increased during the third quarter and first nine 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 third quarter of 2011.
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.
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Interest Expense
Interest based on debt outstanding
Capitalized interest
Interest based on debt outstanding remained relatively flat in 2012 as a result of lower weighted average interest rates offset by additional debt borrowings. Borrowings were primarily used to fund capital expenditures in excess of our operating cash flow and divestiture proceeds.
In the third quarter of 2012, we recognized asset impairments related to our U.S. oil and gas property and equipment and our U.S. midstream assets as presented below.
Under the full-cost method of accounting, capitalized costs of oil and gas properties are subject to a full cost ceiling test, which is discussed in Note 11 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
Additionally, if natural gas and NGL prices remain depressed, we may incur a full cost ceiling impairment related to our oil and gas property and equipment in the fourth quarter of 2012.
Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of its midstream facilities located in south and east Texas were not recoverable from estimated future cash flows. Consequently, the assets were written down to their estimated fair values, which were determined using discounted cash flow models.
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Income Taxes
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the 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
Assumed repatriations
Effective income tax rate
In the table above, the “other” effect is primarily comprised of permanent tax differences for which the dollar amounts do not increase or decrease as our pre-tax earnings do. Generally, such items typically have an insignificant impact on our effective income tax rate. However, these items have a more noticeable impact to our rate for the nine months ended September 30, 2012 because of the relatively low pre-tax earnings for that period.
Earnings (Loss) From Discontinued Operations
Operating earnings (loss)
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”) was our primary source of capital in the first nine months of 2012. Our operating cash flow decreased approximately 10 percent during 2012 primarily due to lower commodity prices and higher expenses, partially offset by additional cash flow from our production growth.
During the first nine months of 2012, our operating cash flow funded approximately 80 percent of our cash payments for capital expenditures, net of divestiture proceeds. Leveraging our liquidity, we 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 nine months of 2012, we increased our debt borrowings by $1.6 billion as a result of issuing $2.5 billion of long-term debt partially offset by the repayment of approximately $0.9 billion of outstanding short-term debt. The additional debt borrowings were primarily used to fund capital expenditures in excess of our operating cash flow.
During the first nine months of 2011, we utilized commercial paper borrowings of $3.2 billion and received $0.5 billion from new debt issuances, net of debt maturities, to fund capital expenditures and common share repurchases.
Divestitures of Property and Equipment
During the third quarter of 2012, we closed our joint venture transaction with Sumitomo Corporation. At closing, Sumitomo paid approximately $400 million and received a 30% interest in the Cline and Midland-Wolfcamp shale plays in Texas. Additionally, Sumitomo is funding approximately $1.0 billion of our share of future exploration, development and drilling costs associated with these plays. Also during the third quarter of 2012, we sold our West Johnson County Plant in north Texas for approximately $90 million.
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 funding 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.
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During the second quarter of 2011, we completed the divestiture of our operations in Brazil, generating $3.3 billion in net proceeds.
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 $5.6 billion and $4.9 billion in the first nine months of 2012 and 2011, respectively. The 14% growth in exploration and development capital spending in the first nine 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.
Short-term Investment Activity, Net
During the first nine months of 2012 and 2011, we had net short-term investment purchases totaling $0.7 billion and $1.1 billion, respectively. The 2012 purchases were primarily related to the investment of a portion of our joint venture proceeds into marketable securities. The 2011 purchases were primarily related to the investment of a portion of the International offshore divestiture proceeds into marketable securities.
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 third 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 nine months of 2012 and 2011.
Repurchases
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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 open oil, gas and NGL derivative financial instruments as of September 30, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
Credit Availability
As of October 24, 2012, we had $2.9 billion of available capacity under our syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) and $3.2 billion of commercial paper borrowings outstanding. Our Senior Credit Facility matures on October 24, 2017. However, prior to the maturity date, we have the option to extend the maturity for up to two additional one-year periods, subject to the approval of the lenders.
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 September 30, 2012, we were in compliance with this covenant with a debt-to-capitalization ratio of 24.7 percent.
Although we ended the third quarter of 2012 with approximately $7.5 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. During 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 approximately $1.7 billion.
Commodity Price Risk
We have commodity derivatives that pertain to a portion of our production for the last three months of 2012, as well as 2013 and 2014. The key terms to our open oil, gas and NGL derivative financial instruments as of September 30, 2012 are presented in Note 2 to the financial statements under “Item 1. Consolidated Financial Statements” of this report.
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The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At September 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 September 30, 2012, we had total debt outstanding of $11.2 billion. Our long-term debt of $8.4 billion bears fixed interest rates averaging 5.4 percent. The remaining $2.8 billion of commercial paper borrowings bears interest at fixed rates which averaged 0.37 percent. Such borrowings typically have maturity rates between 1 and 90 days.
As of September 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 September 30, 2012.
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 September 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 September 30, 2012, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash. The value of the intercompany loans increases or decreases from the remeasurement of the loans into the U.S. dollar functional currency. Based on the amount of the intercompany loans as of September 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 September 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
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 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 third quarter of 2012.
July 1 – July 31
August 1 – August 31
September 1 – September 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 6,200 shares of our common stock in the third 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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