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1. Summary of Significant Accounting Policies
The accompanying unaudited consolidated 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 consolidated financial statements and notes should be read in conjunction with the consolidated financial statements and notes included in Devon's 2008 Annual Report on Form 10-K.
The unaudited interim consolidated 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, 2009 and Devon's results of operations and cash flows for the three-month and six-month periods ended June 30, 2009 and 2008. To prepare the accompanying financial statements and notes, Devon's management evaluated events or transactions that occurred subsequent to June 30, 2009 and before August 5, 2009, which was the date these financial statements were issued.
Recently Issued Accounting Standards Not Yet Adopted
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, "Employers' Disclosures about Postretirement Benefit Plan Assets." Staff Position 132(R)-1 amends FASB Statement No. 132 (revised 2003), Employers' Disclosures about Pensions and Other Postretirement Benefits, to require additional disclosures about the types of assets and associated risks in an employer's defined benefit pension or other postretirement plan. Staff Position 132(R)-1 is effective for fiscal years ending after December 15, 2009. Devon is evaluating the impact the adoption of Staff Position 132(R)-1 will have on its financial statement disclosures. However, Devon's adoption of Staff Position 132(R)-1 will not affect its current accounting for its pension and postretirement plans.
Modernization of Oil and Gas Reporting
In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves. In the three decades that have passed since adoption of these disclosure items, there have been significant changes in the oil and gas industry. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. In addition, the amendments concurrently align the SEC's full cost accounting rules with the revised disclosures. The revised disclosure requirements must be incorporated in registration statements filed on or after January 1, 2010, and annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.
The following amendments have the greatest likelihood of affecting Devon's reserve disclosures, including the comparability of its reserves disclosures with those of its peer companies:
· Pricing mechanism for oil and gas reserves estimation – The SEC's current rules require proved reserve estimates to be calculated using prices as of the end of the period and held constant over the life of the reserves. Price changes can be made only to the extent provided by contractual arrangements. The revised rules require reserve estimates to be calculated using a 12-month average price. The 12-month average price will also be used for purposes of calculating the full cost ceiling limitations. Price changes can still be incorporated to the extent defined by contractual arrangements. The use of a 12-month average price rather than a single-day price is expected to reduce the impact on reserve estimates and the full cost ceiling limitations due to short-term volatility and seasonality of prices.
· Reasonable certainty – The SEC's current definition of "proved oil and gas reserves" incorporate certain specific concepts such as "lowest known hydrocarbons," which limits the ability to claim proved reserves in the absence of information on fluid contacts in a well penetration, notwithstanding the existence of other engineering and geoscientific evidence. The revised rules amend the definition to permit the use of new reliable technologies to establish the reasonable certainty of proved reserves. This revision also includes provisions for establishing levels of lowest known hydrocarbons and highest known oil through reliable technology other than well penetrations.
The revised rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic producibility can be established with reasonable certainty. These revisions are designed to permit the use of reliable technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells.
Because the revised rules generally expand the definition of proved reserves, Devon expects its proved reserve estimates will increase upon adoption of the revised rules. However, Devon is not able to estimate the magnitude of the potential increase at this time.
· Unproved reserves – The SEC's current rules prohibit disclosure of reserve estimates other than proved in documents filed with the SEC. The revised rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible reserves. Disclosure of probable and possible reserves is optional. However, such disclosures must meet specific requirements. Disclosures of probable or possible reserves must provide the same level of geographic detail as proved reserves and must state whether the reserves are developed or undeveloped. Probable and possible reserve disclosures must also provide the relative uncertainty associated with these classifications of reserves estimations. Devon has not yet determined whether it will disclose its probable and possible reserves in documents filed with the SEC.
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The components of accounts receivable include the following:
|
June 30, 2009 |
December 31, 2008 |
|
(In millions) |
|
Oil, gas and NGL revenues............................................................................ |
$ 719 |
$ 789 |
Joint interest billings........................................................................................ |
207 |
263 |
Marketing and midstream revenues............................................................ |
127 |
153 |
Production tax credits..................................................................................... |
210 |
170 |
Other.................................................................................................................. |
61 |
42 |
Gross accounts receivable......................................................................... |
1,324 |
1,417 |
Allowance for doubtful accounts................................................................. |
(6) |
(5) |
Net accounts receivable............................................................................. |
$ 1,318 |
$ 1,412 |
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3. Derivative Financial Instruments
Devonperiodically enters into commodity and interest rate derivative financial instruments. These instruments are used to manage the inherent uncertainty of future revenues due to oil and gas price volatility and to manage Devon's exposure to interest rate volatility. Also, during the first eight months of 2008, Devon was subject to an embedded option derivative related to the fair value of its debentures exchangeable into shares of Chevron common stock.
The following table presents the fair values of derivative assets and liabilities included in the accompanying balance sheets. None of Devon's derivative instruments included in the table have been designated as hedging instruments.
|
Balance Sheet Caption |
Asset |
Liability |
|
|
(In millions) |
|
June 30, 2009: |
|
|
|
Gas price collars................... |
Derivative financial instruments, current.............................. |
$ 190 |
$ — |
Interest rate swaps.............. |
Derivative financial instruments, current.............................. |
36 |
— |
Interest rate swaps.............. |
Long-term other assets............................................................. |
62 |
— |
Total derivatives.............................................................................................................................. |
$ 288 |
$ — |
|
|
|
|
|
December 31, 2008: |
|
|
|
Gas price collars................... |
Derivative financial instruments, current.............................. |
$ 255 |
$ — |
Interest rate swaps.............. |
Derivative financial instruments, current.............................. |
27 |
— |
Interest rate swaps.............. |
Long-term other assets............................................................. |
77 |
— |
Total derivatives.............................................................................................................................. |
$ 359 |
$ — |
The following table presents the cash settlements and unrealized gains and losses on fair value changes included in the accompanying statements of operations associated with these derivative financial instruments. None of Devon's derivative instruments included in the table have been designated as hedging instruments.
|
Three Months Ended June 30, |
Six Months Ended June 30, |
||
|
2009 |
2008 |
2009 |
2008 |
|
(In millions) |
|||
Cash settlements receipts (payments): |
|
|
|
|
Gas price collars (1)......................................................... |
$ 114 |
$ (150) |
$ 232 |
$ (150) |
Gas price swaps (1).......................................................... |
— |
(153) |
— |
(161) |
Interest rate swaps (2)..................................................... |
5 |
— |
21 |
— |
Total cash settlements................................................... |
119 |
(303) |
253 |
(311) |
|
|
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|
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Unrealized (losses) gains: |
|
|
|
|
Gas price collars (1)......................................................... |
(101) |
(620) |
(65) |
(1,028) |
Gas price swaps (1).......................................................... |
— |
(247) |
— |
(618) |
Oil price collars (1)........................................................... |
— |
(45) |
— |
(46) |
Interest rate swaps (2)..................................................... |
5 |
— |
(6) |
— |
Embedded option (2)...................................................... |
— |
(155) |
— |
(58) |
Total unrealized losses.................................................... |
(96) |
(1,067) |
(71) |
(1,750) |
Net gain (loss) recognized on statement of operations. |
$ 23 |
$ (1,370) |
$ 182 |
$ (2,061) |
________________
(1) Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s gas price collars, gas price swaps and oil price collars have been recorded in the “Net gain (loss) on oil and gas derivate financial instruments” line item in the accompanying statements of operations.
(2) Cash settlements and unrealized gains and losses on fair value changes associated with Devon’s interest rate swaps and embedded option have been recorded in the “Change in fair value of other financial instruments” line item in the accompanying statements of operations.
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The components of other current assets include the following:
|
June 30, 2009 |
December 31, 2008 |
|
(In millions) |
|
Inventories........................................................................................................ |
$ 275 |
$ 197 |
Prepaid assets................................................................................................... |
43 |
49 |
Other.................................................................................................................. |
40 |
31 |
Other current assets..................................................................................... |
$ 358 |
$ 277 |
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In the first quarter of 2009, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. These reductions are discussed in Note 13.
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During the first six months of 2009, Devon's goodwill increased $131 million. This increase related to Devon's Canadian goodwill and was entirely due to foreign currency translation.
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5.625% Senior Notes Due January 15, 2014 and 6.30% Senior Notes Due January 15, 2019
In January 2009, Devon issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay Devon's $1.0 billion of outstanding commercial paper as of December 31, 2008.
Credit Lines
Devon has two syndicated, unsecured revolving lines of credit that can be accessed to provide liquidity as needed. The following schedule summarizes the capacity of Devon's credit facilities by maturity date, as well as its available capacity as of June 30, 2009.
Description |
Amount |
|
(In millions) |
Senior Credit Facility maturities: |
|
April 7, 2012....................................................................................................... |
$ 500 |
April 7, 2013....................................................................................................... |
2,150 |
Senior Credit Facility total capacity................................................................ |
2,650 |
Short-Term Facility total capacity – November 3, 2009 maturity............ |
700 |
Total credit facility capacity............................................................................. |
3,350 |
Less: |
|
Outstanding credit facility borrowings........................................................... |
— |
Outstanding commercial paper borrowings.................................................. |
1,330 |
Outstanding letters of credit............................................................................ |
111 |
Total available capacity.................................................................................... |
$ 1,909 |
The credit facilities contain only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization to be less than 65%. The credit agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective amounts reported in the consolidated financial statements. Also, total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling impairments or goodwill impairments. As of June 30, 2009, Devon was in compliance with this covenant. Devon’s debt-to-capitalization ratio at June 30, 2009, as calculated pursuant to the terms of the agreement, was 21.8%.
Commercial Paper
Subsequent to the $1.0 billion commercial paper repayment in January 2009, Devon utilized additional commercial paper borrowings of $1.3 billion to fund capital expenditure payments in excess of cash generated by operating activities during the first half of 2009. As of June 30, 2009, Devon’s average borrowing rate on its $1.3 billion of commercial paper debt was 0.48%.
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8. Asset Retirement Obligations
The following is a summary of the changes in Devon’s asset retirement obligations (“ARO”) for the first six months of 2009 and 2008.
|
Six Months Ended June 30, |
|
|
2009 |
2008 |
|
(In millions) |
|
ARO as of beginning of period........................................................................................................ |
$ 1,485 |
$ 1,318 |
Liabilities incurred............................................................................................................................ |
43 |
29 |
Liabilities settled............................................................................................................................... |
(43) |
(40) |
Revision of estimated obligation................................................................................................... |
23 |
162 |
Accretion expense on discounted obligation............................................................................... |
48 |
44 |
Foreign currency translation adjustment..................................................................................... |
30 |
(20) |
ARO as of end of period................................................................................................................... |
1,586 |
1,493 |
Less current portion........................................................................................................................... |
175 |
63 |
ARO, long-term................................................................................................................................... |
$ 1,411 |
$ 1,430 |
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Net Periodic Benefit Cost and Other Comprehensive Income
The following table presents the components of net periodic benefit cost and other comprehensive income for Devon’s pension and other post retirement benefit plans for the three-month and six-month periods ended June 30, 2009 and 2008.
|
Pension Benefits |
Other Postretirement Benefits |
||||||
|
Three Months Ended June 30, |
Six Months Ended June 30, |
Three Months Ended June 30, |
Six Months Ended June 30, |
||||
|
2009 |
2008 |
2009 |
2008 |
2009 |
2008 |
2009 |
2008 |
|
(In millions) |
|||||||
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
Service cost....................................... |
$ 11 |
$ 10 |
$ 22 |
$ 20 |
$ — |
$ — |
$ — |
$ — |
Interest cost...................................... |
14 |
14 |
28 |
28 |
1 |
2 |
2 |
4 |
Expected return on plan assets..... |
(9) |
(13) |
(18) |
(26) |
— |
— |
— |
— |
Amortization of prior service cost |
1 |
— |
2 |
— |
— |
— |
— |
— |
Net actuarial loss............................. |
11 |
4 |
22 |
8 |
— |
— |
— |
— |
Net periodic benefit cost.............. |
28 |
15 |
56 |
30 |
1 |
2 |
2 |
4 |
Other comprehensive income: |
|
|
|
|
|
|
|
|
Recognition of prior service cost in net periodic benefit cost.......... |
(1) |
— |
(2) |
— |
— |
— |
— |
— |
Recognition of net actuarial loss in net periodic benefit cost.......... |
(11) |
(4) |
(22) |
(8) |
— |
— |
— |
— |
Total recognized................................ |
$ 16 |
$ 11 |
$ 32 |
$ 22 |
$ 1 |
$ 2 |
$ 2 |
$ 4 |
Devon previously disclosed in its 2008 Annual Report on Form 10-K that it expected to contribute up to approximately $183 million to its defined benefit pension plans in 2009 and $5 million to its defined benefit postretirement plans in 2009. Devon has revised its estimate of 2009 defined benefit pension plan contributions to $55 million. As of June 30, 2009, Devon has contributed $15 million to its defined benefit pension plans and $2 million to its defined benefit postretirement plans.
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Stock Repurchases
During the first six months of 2008, Devon repurchased 2.8 million common shares for $302 million, or $106.01 per share, under programs approved by its Board of Directors. The 2.8 million common shares include 2.0 million shares that were repurchased under Devon's 50 million share repurchase program and 0.8 million shares that were repurchased under Devon's ongoing, annual stock repurchase program. No such repurchases were made during the first six months of 2009.
Dividends
Devon paid common stock dividends of $142 million and $141 million (quarterly rates of $0.16 per share) in the first six months of 2009 and 2008, respectively. Devon paid preferred stock dividends of $5 million in the first half of 2008. Devon redeemed all 1.5 million outstanding shares of its preferred stock on June 20, 2008.
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11. 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 that 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. However, actual amounts could differ materially from management's estimate.
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 ("CERCLA") and similar state statutes. In response to liabilities associated with these activities, accruals have been established when reasonable estimates are possible. Such accruals primarily include estimated costs associated with remediation. Devon has not used discounting in determining its accrued liabilities for environmental remediation, and no material claims for possible recovery from third party insurers or other parties related to environmental costs have been recognized in Devon's consolidated financial statements. Devon adjusts the accruals when new remediation responsibilities are discovered and probable costs become estimable, or when current remediation estimates must be adjusted to reflect new information.
Certain of Devon's subsidiaries are involved in matters in which it has been alleged that such subsidiaries are potentially responsible parties ("PRPs") under CERCLA or similar state legislation with respect to various waste disposal areas owned or operated by third parties. As of June 30, 2009, Devon's balance sheet included $1 million of accrued liabilities, reflected in other long-term liabilities, related to these and other environmental remediation liabilities. Devon does not currently believe there is a reasonable possibility of incurring additional material costs in excess of the current accruals recognized for such environmental remediation activities. With respect to the sites in which Devon subsidiaries are PRPs, Devon's conclusion is based in large part on (i) Devon's participation in consent decrees with both other PRPs and the Environmental Protection Agency, which provide for performing the scope of work required for remediation and contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devon's monetary exposure is not expected to be material.
Royalty Matters
Numerous
natural gas producers and related parties, including Devon,
have been named in various lawsuits alleging violation of the federal False
Claims Act. The suits allege that the producers and related parties used
below-market prices, improper deductions, improper measurement techniques and
transactions with affiliates, which resulted in underpayment of royalties in
connection with natural gas and NGLs produced and sold from federal and Indian
owned or controlled lands. The principal suit in which Devon is a defendant is United
States
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the "MMS") have contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price thresholds.
The U.S. House of Representatives in January 2007 passed legislation that would have required companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases. This legislation was not passed by the U.S. Senate. However, Congress may consider similar legislation in the future. In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. Additionally, in January 2009 a federal appellate court upheld this district court ruling. This judgment is subject to further appeals.
As of June 30, 2009, Devon had $82 million accrued for potential royalties on various deep water leases. Due to the uncertainty of this issue caused by the favorable federal court decisions and potential Congressional actions, Devon has ceased accruing additional royalties on its affected leases. Devon will continue to monitor developments and adjust its accruals as necessary.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business. However, to Devon's knowledge as of the date these financial statements were issued, neither Devon nor its property is subject to any material pending legal proceedings.
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Certain of Devon's assets and liabilities are reported at fair value in the accompanying balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial instruments. The following tables provide carrying value and fair value measurement information for such assets and liabilities as of June 30, 2009 and December 31, 2008.
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As of June 30, 2009 |
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|
|
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Fair Value Measurements Using: |
||
|
Carrying Amount |
Total Fair Value |
Quoted Prices in Active Markets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
|
(In millions) |
||||
Financial Assets (Liabilities): |
|
|
|
|
|
Long-term investments............................................ |
$ 118 |
$ 118 |
$ — |
$ — |
$ 118 |
Gas price collars......................................................... |
$ 190 |
$ 190 |
$ — |
$ 190 |
$ — |
Interest rate swaps.................................................... |
$ 98 |
$ 98 |
$ — |
$ 98 |
$ — |
Debt............................................................................. |
$ (7,357) |
$ (8,000) |
$ (1,330) |
$ (6,670) |
$ — |
Asset retirement obligations........................................ |
$ (1,586) |
$ (1,586) |
$ — |
$ — |
$ (1,586) |
|
As of December 31, 2008 |
||||
|
|
|
Fair Value Measurements Using: |
||
|
Carrying Amount |
Total Fair Value |
Quoted Prices in Active Markets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
|
(In millions) |
||||
Financial Assets (Liabilities): |
|
|
|
|
|
Long-term investments............................................ |
$ 122 |
$ 122 |
$ — |
$ — |
$ 122 |
Gas price collars......................................................... |
$ 255 |
$ 255 |
$ — |
$ 255 |
$ — |
Interest rate swaps.................................................... |
$ 104 |
$ 104 |
$ — |
$ 104 |
$ — |
Debt............................................................................. |
$ (5,841) |
$ (6,106) |
$ (1,005) |
$ (5,101) |
$ — |
Asset retirement obligations........................................ |
$ (1,485) |
$ (1,485) |
$ — |
$ — |
$ (1,485) |
A summary of the changes in Devon's asset retirement obligations during the first half of 2009 is included in Note 8. Included below is a summary of the changes in Devon's other Level 3 fair value measurements during the first half of 2009 (in millions).
Beginning balance......................................................... |
$ 122 |
Redemptions of principal............................................. |
(4) |
Ending balance.............................................................. |
$ 118 |
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13. Reduction of Carrying Value of Oil and Gas Properties
In the first quarter of 2009, Devon reduced the carrying values of certain of its oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
|
March 31, 2009 |
|
|
Gross |
Net of Taxes |
|
(In millions) |
|
United States.................................................................... |
$ 6,408 |
$ 4,085 |
Brazil................................................................................. |
103 |
103 |
Russia................................................................................ |
5 |
2 |
Total............................................................................... |
$ 6,516 |
$ 4,190 |
The United States reduction resulted primarily from a significant decrease in the full cost ceiling during the first three months of 2009. The lower ceiling value in the United States largely resulted from the continued effects of declining natural gas prices subsequent to December 31, 2008.
Although oil prices improved subsequent to December 31, 2008, Brazil's reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, Devon concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.
To demonstrate the changes in the full-cost ceiling for the United States and Brazil, the March 31, 2009 and December 31, 2008 weighted average wellhead prices are presented in the following table.
|
March 31, 2009 |
December 31, 2008 |
||||
Country |
Oil (Per Bbl) |
Gas (Per Mcf) |
NGLs (Per Bbl) |
Oil (Per Bbl) |
Gas (Per Mcf) |
NGLs (Per Bbl) |
United States.......................... |
$47.30 |
$2.67 |
$17.04 |
$42.21 |
$4.68 |
$16.16 |
Brazil....................................... |
$36.71 |
N/A |
N/A |
$26.61 |
N/A |
N/A |
__________________
N/A – Not applicable.
The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas.
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At the end of 2008, Devon's operations in Angola were classified as discontinued as a result of Devon's plans and ongoing activities to sell its operations in Angola. Due to a commercial discovery in the second quarter of 2009, Devon suspended marketing its Angolan operations for sale. Although Devon intends to resume marketing activities in 2010 once it has drilled its remaining commitment wells, Devon's operations in Angola do not currently qualify as discontinued. Therefore, Devon has classified all amounts related to its Angolan operations for 2009 and prior years as continuing operations.
In the second quarter of 2008, Devon sold its assets and terminated its operations in certain West African countries, consisting primarily of Equatorial Guinea and Gabon. As a result of the sales, Devon recognized gains totaling $736 million ($647 million after taxes) in the second quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price adjustments). During the second quarter of 2009, Devon recognized a $17 million gain in conjunction with post-closing settlements related to these sales, as well as the sale of its assets in Cote D'Ivoire in the third quarter of 2008.
Operating revenues related to Devon’s discontinued operations totaled $127 million in the three months ended June 30, 2008 and $332 million in the six months ended June 30, 2008. There were no operating revenues related to Devon's discontinued operations for the three-month and six-month periods ended June 30, 2009.
The following table presents the main classes of assets and liabilities associated with Devon’s discontinued operations as of June 30, 2009 and December 31, 2008.
|
Devon's Consolidated Balance Sheet Caption |
June 30, 2009 |
December 31, 2008 |
|
|
(In millions) |
|
Cash and other current assets.................................................... |
Other current assets |
$ 18 |
$ 14 |
Property and equipment, net of accumulated depreciation, depletion and amortization...................................................... |
Other long-term assets |
$ 8 |
$ 9 |
Accounts payable and other current liabilities........................ |
Other current liabilities |
$ 10 |
$ 6 |
|
Following is certain financial information regarding Devon’s reporting segments. The revenues reported are all from external customers.
|
Domestic |
Canada |
International |
Total |
|
(In millions) |
|||
As of June 30, 2009: |
|
|
|
|
Current assets........................................................................... |
$ 1,477 |
$ 555 |
$ 545 |
$ 2,577 |
Property and equipment, net................................................. |
12,364 |
4,774 |
949 |
18,087 |
Goodwill.................................................................................... |
3,046 |
2,596 |
68 |
5,710 |
Other long-term assets............................................................ |
417 |
57 |
209 |
683 |
Total assets.......................................................................... |
$ 17,304 |
$ 7,982 |
$ 1,771 |
$ 27,057 |
|
|
|
|
|
Current liabilities...................................................................... |
$ 2,851 |
$ 401 |
$ 240 |
$ 3,492 |
Long-term debt........................................................................ |
2,870 |
2,979 |
— |
5,849 |
Asset retirement obligation, long-term................................. |
724 |
586 |
101 |
1,411 |
Other long-term liabilities....................................................... |
992 |
42 |
2 |
1,036 |
Deferred income taxes............................................................ |
540 |
950 |
97 |
1,587 |
Stockholders' equity................................................................ |
9,327 |
3,024 |
1,331 |
13,682 |
Total liabilities and stockholders' equity........................ |
$ 17,304 |
$ 7,982 |
$ 1,771 |
$ 27,057 |
|
Domestic |
Canada |
International |
Total |
|
(In millions) |
|||
Three Months Ended June 30, 2009: |
|
|
|
|
Revenues: |
|
|
|
|
Oil sales.............................................................................................. |
$ 225 |
$ 316 |
$ 267 |
$ 808 |
Gas sales............................................................................................ |
544 |
195 |
1 |
740 |
NGL sales........................................................................................... |
138 |
32 |
— |
170 |
Net gain on oil and gas derivative financial instruments.......... |
13 |
— |
— |
13 |
Marketing and midstream revenues............................................. |
351 |
8 |
— |
359 |
Total revenues............................................................................... |
1,271 |
551 |
268 |
2,090 |
Expenses and other income, net: |
|
|
|
|
Lease operating expenses............................................................... |
289 |
167 |
54 |
510 |
Production taxes............................................................................... |
27 |
1 |
19 |
47 |
Marketing and midstream operating costs and expenses......... |
230 |
4 |
— |
234 |
Depreciation, depletion and amortization of oil and gas properties........................................................................................ |
274 |
156 |
64 |
494 |
Depreciation and amortization of non-oil and gas properties. |
67 |
7 |
— |
74 |
Accretion of asset retirement obligation...................................... |
14 |
9 |
1 |
24 |
General and administrative expenses........................................... |
153 |
31 |
(2) |
182 |
Interest expense................................................................................ |
34 |
56 |
— |
90 |
Change in fair value of other financial instruments.................. |
(10) |
— |
— |
(10) |
Other expense (income), net........................................................... |
18 |
6 |
(4) |
20 |
Total expenses and other income, net....................................... |
1,096 |
437 |
132 |
1,665 |
Earnings from continuing operations before income taxes........ |
175 |
114 |
136 |
425 |
Income tax expense (benefit): |
|
|
|
|
Current............................................................................................... |
11 |
44 |
(4) |
51 |
Deferred............................................................................................. |
55 |
(4) |
26 |
77 |
Total income tax expense........................................................... |
66 |
40 |
22 |
128 |
Earnings from continuing operations............................................. |
109 |
74 |
114 |
297 |
Earnings from discontinued operations......................................... |
— |
— |
17 |
17 |
Net earnings applicable to common stockholders....................... |
$ 109 |
$ 74 |
$ 131 |
$ 314 |
|
|
|
|
|
Capital expenditures, continuing operations................................. |
$ 761 |
$ 185 |
$ 113 |
$ 1,059 |
|
Domestic |
Canada |
International |
Total |
|
(In millions) |
|||
Three Months Ended June 30, 2008: |
|
|
|
|
Revenues: |
|
|
|
|
Oil sales.............................................................................................. |
$ 566 |
$ 498 |
$ 391 |
$ 1,455 |
Gas sales............................................................................................ |
1,688 |
517 |
5 |
2,210 |
NGL sales........................................................................................... |
305 |
74 |
— |
379 |
Net loss on oil and gas derivative financial instruments........... |
(1,215) |
— |
— |
(1,215) |
Marketing and midstream revenues............................................. |
707 |
12 |
— |
719 |
Total revenues............................................................................... |
2,051 |
1,101 |
396 |
3,548 |
Expenses and other income, net: |
|
|
|
|
Lease operating expenses............................................................... |
279 |
211 |
47 |
537 |
Production taxes............................................................................... |
104 |
1 |
71 |
176 |
Marketing and midstream operating costs and expenses......... |
510 |
5 |
— |
515 |
Depreciation, depletion and amortization of oil and gas properties........................................................................................ |
481 |
227 |
54 |
762 |
Depreciation and amortization of non-oil and gas properties. |
54 |
7 |
1 |
62 |
Accretion of asset retirement obligation...................................... |
10 |
10 |
2 |
22 |
General and administrative expenses........................................... |
145 |
34 |
1 |
180 |
Interest expense................................................................................ |
36 |
54 |
— |
90 |
Change in fair value of other financial instruments.................. |
(40) |
— |
— |
(40) |
Other income, net............................................................................. |
(11) |
— |
(6) |
(17) |
Total expenses and other income, net....................................... |
1,568 |
549 |
170 |
2,287 |
Earnings from continuing operations before income taxes........ |
483 |
552 |
226 |
1,261 |
Income tax expense (benefit): |
|
|
|
|
Current............................................................................................... |
299 |
46 |
69 |
414 |
Deferred............................................................................................. |
163 |
104 |
(14) |
253 |
Total income tax expense........................................................... |
462 |
150 |
55 |
667 |
Earnings from continuing operations............................................. |
21 |
402 |
171 |
594 |
Discontinued operations: |
|
|
|
|
Earnings from discontinued operations before income taxes.. |
— |
— |
851 |
851 |
Income tax expense........................................................................ |
— |
— |
144 |
144 |
Earnings from discontinued operations....................................... |
— |
— |
707 |
707 |
Net earnings......................................................................................... |
21 |
402 |
878 |
1,301 |
Preferred stock dividends.................................................................. |
3 |
— |
— |
3 |
Net earnings applicable to common stockholders....................... |
$ 18 |
$ 402 |
$ 878 |
$ 1,298 |
|
|
|
|
|
Capital expenditures, continuing operations................................. |
$ 1,654 |
$ 182 |
$ 173 |
$ 2,009 |
|
Domestic |
Canada |
International |
Total |
||||
|
(In millions) |
|||||||
Six Months Ended June 30, 2009: |
|
|
|
|
||||
Revenues: |
|
|
|
|
||||
Oil sales.............................................................................................. |
$ 375 |
$ 493 |
$ 394 |
$ 1,262 |
||||
Gas sales............................................................................................ |
1,220 |
431 |
2 |
1,653 |
||||
NGL sales........................................................................................... |
250 |
56 |
— |
306 |
||||
Net gain on oil and gas derivative financial instruments.......... |
167 |
— |
— |
167 |
||||
Marketing and midstream revenues............................................. |
715 |
15 |
— |
730 |
||||
Total revenues............................................................................... |
2,727 |
995 |
396 |
4,118 |
||||
Expenses and other income, net: |
|
|
|
|
||||
Lease operating expenses............................................................... |
602 |
344 |
88 |
1,034 |
||||
Production taxes............................................................................... |
59 |
1 |
29 |
89 |
||||
Marketing and midstream operating costs and expenses......... |
455 |
8 |
— |
463 |
||||
Depreciation, depletion and amortization of oil and gas properties........................................................................................ |
714 |
276 |
103 |
1,093 |
||||
Depreciation and amortization of non-oil and gas properties. |
131 |
13 |
— |
144 |
||||
Accretion of asset retirement obligation...................................... |
28 |
18 |
2 |
48 |
||||
General and administrative expenses........................................... |
290 |
60 |
(2) |
348 |
||||
Interest expense................................................................................ |
61 |
112 |
— |
173 |
||||
Change in fair value of other financial instruments.................. |
(15) |
— |
— |
(15) |
||||
Reduction of carrying value of oil and gas properties............... |
6,408 |
— |
108 |
6,516 |
||||
Other expense (income), net........................................................... |
14 |
16 |
(3) |
27 |
||||
Total expenses and other income, net....................................... |
8,747 |
848 |
325 |
9,920 |
||||
(Loss) earnings from continuing operations before income taxes................................................................................................... |
(6,020) |
147 |
71 |
(5,802) |
||||
Income tax expense (benefit): |
|
|
|
|
||||
Current............................................................................................... |
1 |
46 |
6 |
53 |
||||
Deferred............................................................................................. |
(2,224) |
3 |
27 |
(2,194) |
||||
Total income tax (benefit) expense........................................... |
(2,223) |
49 |
33 |
(2,141) |
||||
(Loss) earnings from continuing operations.................................. |
(3,797) |
98 |
38 |
(3,661) |
||||
Earnings from discontinued operations......................................... |
— |
— |
16 |
16 |
||||
Net (loss) earnings applicable to common stockholders............. |
$ (3,797) |
$ 98 |
$ 54 |
$ (3,645) |
||||
|
|
|
|
|
||||
Capital expenditures, before revision of future ARO.................. |
$ 1,908 |
$ 486 |
$ 203 |
$ 2,597 |
||||
Revision of future ARO.................................................................... |
37 |
(15) |
1 |
23 |
||||
Capital expenditures, continuing operations................................. |
$ 1,945 |
$ 471 |
$ 204 |
$ 2,620 |
||||
|
Domestic |
Canada |
International |
Total |
|
(In millions) |
|||
Six Months Ended June 30, 2008: |
|
|
|
|
Revenues: |
|
|
|
|
Oil sales.............................................................................................. |
$ 1,009 |
$ 838 |
$ 858 |
$ 2,705 |
Gas sales............................................................................................ |
2,924 |
906 |
10 |
3,840 |
NGL sales........................................................................................... |
571 |
136 |
— |
707 |
Net loss on oil and gas derivative financial instruments........... |
(2,003) |
— |
— |
(2,003) |
Marketing and midstream revenues............................................. |
1,249 |
25 |
— |
1,274 |
Total revenues............................................................................... |
3,750 |
1,905 |
868 |
6,523 |
Expenses and other income, net: |
|
|
|
|
Lease operating expenses............................................................... |
545 |
405 |
93 |
1,043 |
Production taxes............................................................................... |
183 |
2 |
125 |
310 |
Marketing and midstream operating costs and expenses......... |
887 |
10 |
— |
897 |
Depreciation, depletion and amortization of oil and gas properties........................................................................................ |
941 |
438 |
120 |
1,499 |
Depreciation and amortization of non-oil and gas properties. |
105 |
13 |
1 |
119 |
Accretion of asset retirement obligation...................................... |
21 |
20 |
3 |
44 |
General and administrative expenses........................................... |
259 |
68 |
1 |
328 |
Interest expense................................................................................ |
88 |
104 |
— |
192 |
Change in fair value of other financial instruments.................. |
(24) |
— |
— |
(24) |
Other income, net............................................................................. |
(17) |
(5) |
(16) |
(38) |
Total expenses and other income, net....................................... |
2,988 |
1,055 |
327 |
4,370 |
Earnings from continuing operations before income taxes........ |
762 |
850 |
541 |
2,153 |
Income tax expense: |
|
|
|
|
Current............................................................................................... |
345 |
64 |
108 |
517 |
Deferred............................................................................................. |
213 |
152 |
26 |
391 |
Total income tax expense........................................................... |
558 |
216 |
134 |
908 |
Earnings from continuing operations............................................. |
204 |
634 |
407 |
1,245 |
Discontinued operations: |
|
|
|
|
Earnings from discontinued operations before income taxes.. |
— |
— |
1,040 |
1,040 |
Income tax expense........................................................................ |
— |
— |
235 |
235 |
Earnings from discontinued operations....................................... |
— |
— |
805 |
805 |
Net earnings......................................................................................... |
204 |
634 |
1,212 |
2,050 |
Preferred stock dividends.................................................................. |
5 |
— |
— |
5 |
Net earnings applicable to common stockholders....................... |
$ 199 |
$ 634 |
$ 1,212 |
$ 2,045 |
|
|
|
|
|
Capital expenditures, before revision of future ARO.................. |
$ 2,965 |
$ 698 |
$ 304 |
$ 3,967 |
Revision of future ARO.................................................................... |
70 |
73 |
19 |
162 |
Capital expenditures, continuing operations................................. |
$ 3,035 |
$ 771 |
$ 323 |
$ 4,129 |
|
17. Supplemental Information to Statements of Cash Flows
Additional information related to Devon’s cash flows for the six-month periods ended June 30, 2009 and 2008 are presented below.
|
Six Months Ended June 30, |
|
|
2009 |
2008 |
|
(In millions) |
|
Net increase in working capital: |
|
|
Decrease (increase) in accounts receivable.......................................................... |
$ 108 |
$ (604) |
Decrease (increase) in other current assets........................................................... |
167 |
(44) |
(Decrease) increase in accounts payable............................................................. |
(66) |
120 |
(Decrease) increase in revenues and royalties due to others............................. |
(115) |
348 |
(Decrease) increase in other current liabilities...................................................... |
(183) |
48 |
Net increase in working capital........................................................................... |
$ (89) |
$ (132) |
|
|
|
Supplementary cash flow data – continuing and discontinued operations: |
|
|
Interest paid – net of capitalized interest............................................................. |
$ 138 |
$ 189 |
Income taxes (received) paid................................................................................. |
$ (139) |
$ 826 |