e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2010
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
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73-1567067 |
(State of other jurisdiction of incorporation or organization)
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(I.R.S. Employer identification No.) |
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20 North Broadway, Oklahoma City, Oklahoma
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73102-8260 |
(Address of principal executive offices)
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(Zip code) |
Registrants telephone number, including area code: (405) 235-3611
Former name, former 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 o
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 o
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. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Exchange Act). Yes o No þ
On April 30, 2010, 446.9 million shares of common stock were outstanding.
[This page intentionally left blank.]
2
DEVON ENERGY CORPORATION
FORM 10-Q
For the Quarterly Period Ended March 31, 2010
INDEX
3
DEFINITIONS
Measurements of Oil, Natural Gas and Natural Gas Liquids
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NGL or NGLs means natural gas liquids. |
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Oil includes crude oil and condensate. |
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Bbl means barrel of oil. One barrel equals 42 U.S. gallons. |
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MBbls means thousand barrels. |
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MMBbls means million barrels. |
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MBbls/d means thousand barrels per day. |
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Mcf means thousand cubic feet of natural gas. |
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MMcf means million cubic feet. |
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Bcf means billion cubic feet. |
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MMcf/d means million cubic feet per day. |
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Boe means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. |
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MBoe means thousand Boe. |
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- |
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MMBoe means million Boe. |
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- |
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MBoe/d means thousand Boe per day. |
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Btu means British thermal units, a measure of heating value. |
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MMBtu means million Btu. |
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- |
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MMBtu/d means million Btu per day. |
Geographic Areas
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Canada means the operations of Devon encompassing oil and gas properties located in Canada. |
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International means the discontinued operations of Devon that encompass oil and gas
properties that lie outside the United States and Canada. |
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North American Onshore means the operations of Devon encompassing oil and gas
properties in the continental United States and Canada. |
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U.S. Offshore means the operations of Devon encompassing oil and gas properties in the
Gulf of Mexico. |
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U.S. Onshore means the properties of Devon encompassing oil and gas properties in the
continental United States. |
Other
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Federal Funds Rate means the interest rate at which depository institutions lend
balances at the Federal Reserve to other depository institutions overnight. |
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Inside FERC refers to the publication Inside F.E.R.C.s Gas Market Report. |
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LIBOR means London Interbank Offered Rate. |
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NYMEX means New York Mercantile Exchange. |
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SEC means United States Securities and Exchange Commission. |
4
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements other than statements of historical facts included or incorporated by
reference in this report, including, without limitation, statements regarding our future financial
position, business strategy, budgets, projected revenues, projected costs and plans and objectives
of management for future operations, are forward-looking statements. Such forward-looking
statements are based on our examination of historical operating trends, the information used to
prepare the December 31, 2009 reserve reports and other data in our possession or available from
third parties. In addition, forward-looking statements generally can be identified by the use of
forward-looking terminology such as may, will, expect, intend, project, estimate,
anticipate, believe, or continue or similar terminology. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can give no assurance
that such expectations will prove to have been correct. Important factors that could cause actual
results to differ materially from our expectations include, but are not limited to, our assumptions
about:
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energy markets, including the supply and demand for oil, gas, NGLs and other products or
services, and the prices of oil, gas, NGLs, including regional pricing differentials, and
other products or services; |
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production levels, including Canadian production subject to government royalties, which
fluctuate with prices and production, and International production governed by payout
agreements, which affect reported production; |
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reserve levels; |
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competitive conditions; |
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technology; |
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the availability of capital resources within the securities or capital markets and
related risks such as general credit, liquidity, market and interest-rate risks; |
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capital expenditure and other contractual obligations; |
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currency exchange rates; |
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the weather; |
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inflation; |
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the availability of goods and services; |
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drilling risks; |
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future processing volumes and pipeline throughput; |
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general economic conditions, whether internationally, nationally or in the jurisdictions
in which we or our subsidiaries conduct business; |
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legislative or regulatory changes, including retroactive royalty or production tax
regimes, changes in environmental regulation, environmental risks and liability under
federal, state and foreign environmental laws and regulations; |
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terrorism; |
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occurrence of property acquisitions or divestitures; and |
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other factors disclosed in Devons 2009 Annual Report on Form 10-K under Item 2.
Properties Preparation of Reserves Estimates and Reserve Audits, Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations, and Item 7A.
Quantitative and Qualitative Disclosures About Market Risk. |
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. We
assume no duty to update or revise our forward-looking statements based on changes in internal
estimates or expectations or otherwise.
5
PART I.
Financial Information
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Item 1. |
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Consolidated Financial Statements |
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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March 31, |
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December 31, |
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2010 |
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2009 |
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(Unaudited) |
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(In millions, except |
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share data) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
724 |
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$ |
646 |
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Accounts receivable |
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1,296 |
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1,208 |
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Derivative financial instruments |
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733 |
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211 |
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Current assets held for sale |
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731 |
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657 |
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Other current assets |
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264 |
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270 |
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Total current assets |
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3,748 |
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2,992 |
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Property and equipment, at cost, based on the full cost method of accounting
for oil and gas properties ($3,266 million and $4,078 million excluded from
amortization in 2010 and 2009, respectively) |
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61,392 |
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60,475 |
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Less accumulated depreciation, depletion and amortization |
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42,580 |
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41,708 |
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Property and equipment, net |
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18,812 |
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18,767 |
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Goodwill |
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6,018 |
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5,930 |
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Long-term assets held for sale |
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1,409 |
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1,250 |
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Other long-term assets |
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690 |
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747 |
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Total assets |
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$ |
30,677 |
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$ |
29,686 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable trade |
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$ |
1,199 |
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$ |
1,137 |
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Revenues and royalties due to others |
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546 |
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486 |
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Short-term debt |
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240 |
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1,432 |
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Current portion of asset retirement obligations |
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90 |
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95 |
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Current liabilities associated with assets held for sale |
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303 |
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234 |
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Other current liabilities |
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730 |
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418 |
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Total current liabilities |
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3,108 |
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3,802 |
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Long-term debt |
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5,845 |
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5,847 |
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Asset retirement obligations |
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1,637 |
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1,418 |
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Liabilities associated with assets held for sale |
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208 |
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213 |
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Other long-term liabilities |
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921 |
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937 |
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Deferred income taxes |
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2,003 |
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1,899 |
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Stockholders equity: |
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Common stock of $0.10 par value. Authorized 1.0 billion shares;
issued 446.8 million and 446.7 million shares in 2010 and 2009,
respectively |
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45 |
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45 |
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Additional paid-in capital |
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6,577 |
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6,527 |
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Retained earnings |
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8,733 |
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7,613 |
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Accumulated other comprehensive earnings |
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1,600 |
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1,385 |
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Total stockholders equity |
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16,955 |
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15,570 |
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Commitments and contingencies (Note 12) |
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Total liabilities and stockholders equity |
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$ |
30,677 |
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$ |
29,686 |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended |
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March 31, |
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2010 |
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2009 |
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(Unaudited) |
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(In millions, except |
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per share amounts) |
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Revenues: |
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Oil, gas and NGL sales |
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$ |
2,070 |
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$ |
1,375 |
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Net gain on oil and gas derivative financial instruments |
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620 |
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154 |
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Marketing and midstream revenues |
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530 |
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371 |
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Total revenues |
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3,220 |
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1,900 |
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Expenses and other income, net: |
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Lease operating expenses |
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414 |
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440 |
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Taxes other than income taxes |
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101 |
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89 |
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Marketing and midstream operating costs and expenses |
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397 |
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224 |
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Depreciation, depletion and amortization of oil and gas properties |
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426 |
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560 |
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Depreciation and amortization of non-oil and gas properties |
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63 |
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70 |
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Accretion of asset retirement obligations |
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26 |
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23 |
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General and administrative expenses |
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138 |
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163 |
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Interest expense |
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86 |
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83 |
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Change in fair value of other financial instruments |
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(15 |
) |
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(5 |
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Reduction of carrying value of oil and gas properties |
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6,408 |
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Other (income) expense, net |
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(4 |
) |
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7 |
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Total expenses and other income, net |
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1,632 |
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8,062 |
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Earnings (loss) from continuing operations before income taxes |
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1,588 |
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(6,162 |
) |
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Income tax expense (benefit): |
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Current |
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299 |
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(8 |
) |
Deferred |
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215 |
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(2,272 |
) |
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Total income tax expense (benefit) |
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514 |
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(2,280 |
) |
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Earnings (loss) from continuing operations |
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1,074 |
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(3,882 |
) |
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Discontinued operations: |
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Earnings (loss) from discontinued operations before income taxes |
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137 |
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(66 |
) |
Discontinued operations income tax expense |
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19 |
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11 |
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Earnings (loss) from discontinued operations |
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118 |
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(77 |
) |
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Net earnings (loss) |
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$ |
1,192 |
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$ |
(3,959 |
) |
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Basic earnings (loss) from continuing operations per share |
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$ |
2.40 |
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$ |
(8.74 |
) |
Basic earnings (loss) from discontinued operations per share |
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0.27 |
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(0.18 |
) |
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Basic net earnings (loss) per share |
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$ |
2.67 |
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$ |
(8.92 |
) |
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Diluted earnings (loss) from continuing operations per share |
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$ |
2.39 |
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$ |
(8.74 |
) |
Diluted earnings (loss) from discontinued operations per share |
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0.27 |
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(0.18 |
) |
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Diluted net earnings (loss) per share |
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$ |
2.66 |
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$ |
(8.92 |
) |
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See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (LOSS)
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Three Months Ended |
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March 31, |
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2010 |
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2009 |
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(Unaudited) |
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(In millions) |
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Net earnings (loss) |
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$ |
1,192 |
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$ |
(3,959 |
) |
Foreign currency translation: |
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Change in cumulative translation adjustment |
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222 |
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(161 |
) |
Foreign currency translation income tax (expense) benefit |
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(12 |
) |
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11 |
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Foreign currency translation total |
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210 |
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(150 |
) |
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Pension and postretirement benefit plans: |
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Recognition of net actuarial loss and prior service cost in earnings |
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8 |
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12 |
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Pension and postretirement benefit plans income tax expense |
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(3 |
) |
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(4 |
) |
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Pension and postretirement benefit plans total |
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5 |
|
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8 |
|
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Other comprehensive earnings (loss), net of tax |
|
|
215 |
|
|
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(142 |
) |
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|
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Comprehensive earnings (loss) |
|
$ |
1,407 |
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|
$ |
(4,101 |
) |
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|
|
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|
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See accompanying notes to consolidated financial statements.
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
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Accumulated |
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Additional |
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Other |
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Total |
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Common Stock |
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Paid-In |
|
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Retained |
|
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Comprehensive |
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Treasury |
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Stockholders |
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Shares |
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Amount |
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Capital |
|
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Earnings |
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Earnings |
|
|
Stock |
|
|
Equity |
|
|
|
(Unaudited) |
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|
|
(In millions) |
|
Three Months Ended March 31, 2010: |
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Balance as of December 31, 2009 |
|
|
447 |
|
|
$ |
45 |
|
|
$ |
6,527 |
|
|
$ |
7,613 |
|
|
$ |
1,385 |
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|
$ |
|
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|
$ |
15,570 |
|
Net earnings (loss) |
|
|
|
|
|
|
|
|
|
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|
|
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|
1,192 |
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|
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|
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|
|
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|
1,192 |
|
Other comprehensive earnings (loss), net of
tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
215 |
|
|
|
|
|
|
|
215 |
|
Stock option exercises |
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
(2 |
) |
Common stock retired |
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|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
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|
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|
2 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(72 |
) |
|
|
|
|
|
|
|
|
|
|
(72 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2010 |
|
|
447 |
|
|
$ |
45 |
|
|
$ |
6,577 |
|
|
$ |
8,733 |
|
|
$ |
1,600 |
|
|
$ |
|
|
|
$ |
16,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,257 |
|
|
$ |
10,376 |
|
|
$ |
383 |
|
|
$ |
|
|
|
$ |
17,060 |
|
Net earnings (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,959 |
) |
|
|
|
|
|
|
|
|
|
|
(3,959 |
) |
Other comprehensive earnings (loss), net of
tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142 |
) |
|
|
|
|
|
|
(142 |
) |
Stock option exercises |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
(2 |
) |
Common stock retired |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(70 |
) |
|
|
|
|
|
|
|
|
|
|
(70 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2009 |
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,310 |
|
|
$ |
6,347 |
|
|
$ |
241 |
|
|
$ |
|
|
|
$ |
12,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations |
|
$ |
1,074 |
|
|
$ |
(3,882 |
) |
Adjustments to reconcile earnings (loss) from continuing operations |
|
|
|
|
|
|
|
|
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
489 |
|
|
|
630 |
|
Deferred income tax expense (benefit) |
|
|
215 |
|
|
|
(2,272 |
) |
Reduction of carrying value of oil and gas properties |
|
|
|
|
|
|
6,408 |
|
Net unrealized gain on oil and gas derivative financial instruments |
|
|
(524 |
) |
|
|
(36 |
) |
Other noncash charges |
|
|
57 |
|
|
|
63 |
|
Net decrease in working capital |
|
|
50 |
|
|
|
128 |
|
Increase in long-term other assets |
|
|
(2 |
) |
|
|
|
|
Decrease in long-term other liabilities |
|
|
(18 |
) |
|
|
(29 |
) |
|
|
|
|
|
|
|
Cash provided by operating activities continuing operations |
|
|
1,341 |
|
|
|
1,010 |
|
Cash provided by operating activities discontinued operations |
|
|
154 |
|
|
|
37 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
1,495 |
|
|
|
1,047 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from property and equipment divestitures |
|
|
1,257 |
|
|
|
1 |
|
Capital expenditures |
|
|
(1,247 |
) |
|
|
(1,926 |
) |
Redemptions of long-term investments |
|
|
8 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Cash provided by (used in) investing activities continuing operations |
|
|
18 |
|
|
|
(1,923 |
) |
Cash used in investing activities discontinued operations |
|
|
(107 |
) |
|
|
(107 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(89 |
) |
|
|
(2,030 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from borrowings of long-term debt, net of issuance costs |
|
|
|
|
|
|
1,187 |
|
Net commercial paper repayments |
|
|
(1,192 |
) |
|
|
(111 |
) |
Debt repayments |
|
|
|
|
|
|
(1 |
) |
Proceeds from stock option exercises |
|
|
8 |
|
|
|
4 |
|
Dividends paid on common stock |
|
|
(72 |
) |
|
|
(70 |
) |
Excess tax benefits related to share-based compensation |
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Net cash (used in) provided by financing activities |
|
|
(1,253 |
) |
|
|
1,011 |
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
18 |
|
|
|
(11 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
171 |
|
|
|
17 |
|
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale) |
|
|
1,011 |
|
|
|
384 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash related
to assets held for sale) |
|
$ |
1,182 |
|
|
$ |
401 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 Devons 2009 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 Devons
financial position as of March 31, 2010 and Devons results of operations and cash flows for the
three-month periods ended March 31, 2010 and 2009.
2. Accounts Receivable
The components of accounts receivable include the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
(In millions) |
|
Oil, gas and NGL sales |
|
$ |
835 |
|
|
$ |
752 |
|
Joint interest billings |
|
|
157 |
|
|
|
151 |
|
Marketing and midstream revenues |
|
|
169 |
|
|
|
188 |
|
Production tax credits |
|
|
128 |
|
|
|
110 |
|
Other |
|
|
19 |
|
|
|
19 |
|
|
|
|
|
|
|
|
Gross accounts receivable |
|
|
1,308 |
|
|
|
1,220 |
|
Allowance for doubtful accounts |
|
|
(12 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
Net accounts receivable |
|
$ |
1,296 |
|
|
$ |
1,208 |
|
|
|
|
|
|
|
|
3. Derivative Financial Instruments
Devon periodically 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 Devons exposure to interest rate volatility.
The following table presents the fair values of derivative assets and liabilities included in
the accompanying consolidated balance sheets. None of Devons derivative instruments included in
the table have been designated as hedging instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset |
|
|
Liability |
|
|
|
Balance Sheet Caption |
|
Derivatives |
|
|
Derivatives |
|
|
|
|
|
(In millions) |
|
March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
Derivative financial instruments, current |
|
$ |
659 |
|
|
$ |
|
|
Gas price collars |
|
Derivative financial instruments, current |
|
|
35 |
|
|
|
|
|
Gas basis swaps |
|
Other current liabilities |
|
|
|
|
|
|
2 |
|
Oil price collars |
|
Other current liabilities |
|
|
|
|
|
|
34 |
|
Interest rate swaps |
|
Derivative financial instruments, current |
|
|
39 |
|
|
|
|
|
Interest rate swaps |
|
Other long-term assets |
|
|
130 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
$ |
863 |
|
|
$ |
36 |
|
|
|
|
|
|
|
|
|
|
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset |
|
|
Liability |
|
|
|
Balance Sheet Caption |
|
Derivatives |
|
|
Derivatives |
|
|
|
|
|
(In millions) |
|
December 31, 2009: |
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
Derivative financial instruments, current |
|
$ |
169 |
|
|
$ |
|
|
Gas basis swaps |
|
Derivative financial instruments, current |
|
|
3 |
|
|
|
|
|
Oil price collars |
|
Other current liabilities |
|
|
|
|
|
|
38 |
|
Interest rate swaps |
|
Derivative financial instruments, current |
|
|
39 |
|
|
|
|
|
Interest rate swaps |
|
Other long-term assets |
|
|
131 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
|
|
$ |
342 |
|
|
$ |
38 |
|
|
|
|
|
|
|
|
|
|
The following table presents the cash settlements and unrealized gains and losses on fair
value changes included in the accompanying consolidated statements of operations associated with
these derivative financial instruments. None of Devons derivative instruments have been designated
as hedging instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
|
|
Ended March 31, |
|
|
|
Statement of Operations Caption |
|
2010 |
|
|
2009 |
|
|
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
Net gain on oil and gas derivative financial instruments |
|
$ |
98 |
|
|
$ |
|
|
Gas price collars |
|
Net gain on oil and gas derivative financial instruments |
|
|
1 |
|
|
|
118 |
|
Gas basis swaps |
|
Net gain on oil and gas derivative financial instruments |
|
|
(3 |
) |
|
|
|
|
Interest rate swaps |
|
Change in fair value of other financial instruments |
|
|
16 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
|
|
112 |
|
|
|
134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
Net gain on oil and gas derivative financial instruments |
|
|
490 |
|
|
|
|
|
Gas price collars |
|
Net gain on oil and gas derivative financial instruments |
|
|
35 |
|
|
|
36 |
|
Gas basis swaps |
|
Net gain on oil and gas derivative financial instruments |
|
|
(5 |
) |
|
|
|
|
Oil price collars |
|
Net gain on oil and gas derivative financial instruments |
|
|
4 |
|
|
|
|
|
Interest rate swaps |
|
Change in fair value of other financial instruments |
|
|
(1 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
Total unrealized gains |
|
|
|
|
523 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
Net gain recognized |
|
$ |
635 |
|
|
$ |
159 |
|
|
|
|
|
|
|
|
|
|
4. Other Current Assets
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
(In millions) |
|
Inventories |
|
$ |
180 |
|
|
$ |
182 |
|
Prepaid assets |
|
|
39 |
|
|
|
33 |
|
Income taxes receivable |
|
|
21 |
|
|
|
53 |
|
Other |
|
|
24 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Other current assets |
|
$ |
264 |
|
|
$ |
270 |
|
|
|
|
|
|
|
|
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
5. Property and Equipment
Divestitures
In November 2009, Devon announced plans to reposition itself strategically as a high-growth,
North American onshore exploration and production company. As part of this strategic repositioning,
Devon is bringing forward the value of its offshore assets by divesting them.
During the first quarter of 2010, Devon sold its interests in the Jack, St. Malo and Cascade
Lower Tertiary projects in the deepwater Gulf of Mexico for $1.3 billion ($1.1 billion after
taxes). These divestitures involved oil and gas properties with no proved reserves, current
production or revenues. Devon used the proceeds from these divestitures to repay commercial paper
borrowings.
On March 10, 2010, Devon entered into agreements to sell all of its remaining assets in the
deepwater Gulf of Mexico, Brazil and Azerbaijan to BP for $7.0 billion. In addition, BP will assume
Devons leases of the Seadrill West Sirius and Transocean Deepwater Discovery drilling rigs for the
duration of the contract terms. Devon closed the deepwater Gulf of Mexico transaction in April
2010. Devon expects to close the Azerbaijan and Brazil transactions before the end of 2010.
On April 9, 2010, Devon entered into an agreement to sell all its shallow-water Gulf of Mexico
assets for $1.05 billion (approximately $840 million after taxes). Devon expects to close this
transaction in the second quarter of 2010.
On April 30, 2010, Devon entered into an agreement to sell its producing Panyu field located
offshore China for $515 million (approximately $370 million after taxes). Devon expects to close
this transaction in the second quarter of 2010.
Under full cost accounting rules, sales or other dispositions of oil and gas properties are
generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss.
However, if not recognizing a gain or loss on the disposition would otherwise significantly alter
the relationship between a cost centers capitalized costs and proved reserves, then a gain or loss
must be recognized. The Gulf of Mexico divestitures discussed above will not significantly alter
such relationship for Devons United States cost center. Therefore, Devon will not recognize a gain
in connection with the Gulf of Mexico divestitures. Because the Azerbaijan, Brazil and China
divestitures will ultimately involve a complete disposition of a cost center, Devon expects to
record gains when such transactions close.
Oil Sands Joint Venture
In conjunction with the announced divestitures to BP, Devon also announced a heavy oil joint
venture to operate and develop BPs Kirby oil sands leases in Alberta, Canada. Devon will acquire
50 percent of BPs interest in the Kirby oil sands leases for $500 million. Devon expects to close
this transaction in the second quarter of 2010. Devon will also fund $150 million of capital costs
on BPs behalf. The majority of these costs are expected to be paid during 2011 and 2012.
6. Goodwill
During the first three months of 2010, Devons Canadian goodwill increased $88 million. This
increase was entirely due to foreign currency translation.
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Other Current Liabilities
The components of other current liabilities include the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2010 |
|
|
December 31, 2009 |
|
|
|
(In millions) |
|
Income taxes payable |
|
$ |
283 |
|
|
$ |
40 |
|
Deferred income taxes |
|
|
176 |
|
|
|
|
|
Accrued interest |
|
|
67 |
|
|
|
120 |
|
Restructuring costs |
|
|
61 |
|
|
|
61 |
|
Derivative financial instruments |
|
|
36 |
|
|
|
38 |
|
Other |
|
|
107 |
|
|
|
159 |
|
|
|
|
|
|
|
|
Other current liabilities |
|
$ |
730 |
|
|
$ |
418 |
|
|
|
|
|
|
|
|
8. Debt
Commercial Paper
During the first quarter of 2010, Devon repaid $1.2 billion of commercial paper borrowings
primarily with proceeds received from Gulf of Mexico property divestitures. As of March 31, 2010,
Devons average borrowing rate on its $240 million of commercial paper debt was 0.22%.
In early May 2010, Devon reduced the maximum allowed borrowings under its commercial paper
program from $2.85 billion to approximately $2.2 billion.
Credit Lines
As of March 31, 2010, Devon had two revolving lines of credit that could be accessed to
provide liquidity as needed. The following schedule summarizes the capacity of Devons credit
facilities by maturity date, as well as its available capacity as of March 31, 2010 (in millions).
|
|
|
|
|
Senior Credit Facility: |
|
|
|
|
April 7, 2012 maturity |
|
$ |
500 |
|
April 7, 2013 maturity |
|
|
2,150 |
|
|
|
|
|
Total Senior Credit Facility |
|
|
2,650 |
|
Short-Term Facility November 2, 2010 maturity |
|
|
700 |
|
|
|
|
|
Total credit facilities |
|
|
3,350 |
|
Less: |
|
|
|
|
Outstanding credit facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
240 |
|
Outstanding letters of credit |
|
|
88 |
|
|
|
|
|
Total available capacity |
|
$ |
3,022 |
|
|
|
|
|
In early May 2010, Devon cancelled the Short-Term Facility prior to its maturity date. Devon
incurred no cost to cancel the facility and will avoid paying the facility fee that pertains to the
cancellation period.
The Senior Credit Facility and Short-Term Facility contain only one material financial
covenant. This covenant requires Devons 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 March 31, 2010,
Devon was in compliance with this covenant. Devons debt-to-capitalization ratio at March 31, 2010,
as calculated pursuant to the terms of the agreement, was 17.1%.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
9. Asset Retirement Obligations
The schedule below summarizes changes in Devons asset retirement obligations.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Asset retirement obligations as of beginning of period |
|
$ |
1,513 |
|
|
$ |
1,387 |
|
Liabilities incurred |
|
|
16 |
|
|
|
8 |
|
Liabilities settled |
|
|
(47 |
) |
|
|
(26 |
) |
Revision of estimated obligation |
|
|
205 |
|
|
|
22 |
|
Liabilities assumed by others |
|
|
(8 |
) |
|
|
|
|
Accretion expense on discounted obligation |
|
|
26 |
|
|
|
23 |
|
Foreign currency translation adjustment |
|
|
22 |
|
|
|
(17 |
) |
|
|
|
|
|
|
|
Asset retirement obligations as of end of period |
|
|
1,727 |
|
|
|
1,397 |
|
Less current portion |
|
|
90 |
|
|
|
157 |
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term |
|
$ |
1,637 |
|
|
$ |
1,240 |
|
|
|
|
|
|
|
|
During the first quarter of 2010 and 2009, Devon recognized revisions to its asset retirement
obligations totaling $205 million and $22 million, respectively. The primary factors causing the
2010 and 2009 increases were an overall increase in abandonment cost estimates and a decrease in
the discount rate used to present value the obligations.
10. Retirement Plans
Net Periodic Benefit Cost and Other Comprehensive Earnings
The following table presents the components of net periodic benefit cost and other
comprehensive earnings for Devons pension and other post retirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
8 |
|
|
$ |
11 |
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
14 |
|
|
|
14 |
|
|
|
1 |
|
|
|
1 |
|
Expected return on plan assets |
|
|
(9 |
) |
|
|
(9 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Net actuarial loss |
|
|
7 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
|
21 |
|
|
|
28 |
|
|
|
1 |
|
|
|
1 |
|
Other comprehensive earnings: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of prior service cost in net
periodic benefit cost |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
Recognition of net actuarial loss in net
periodic benefit cost |
|
|
(7 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized |
|
$ |
13 |
|
|
$ |
16 |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
11. Stockholders Equity
Dividends
Devon paid common stock dividends of $72 million and $70 million (quarterly rates of $0.16 per
share) in the first quarter of 2010 and 2009, respectively.
12. 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, Devons 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 Devons
financial position or results of operations after consideration of recorded accruals. However,
actual amounts could differ materially from managements 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 and similar state statutes. In response to liabilities associated
with these activities, loss accruals primarily consist of estimated uninsured costs associated with
remediation. Devons monetary exposure for environmental matters 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. Devon does not currently believe that it is subject to material exposure with respect to
such royalty matters.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business.
However, to Devons knowledge as of the date of this report, neither Devon nor its property is
subject to any material pending legal proceedings.
Commitments
At the end of 2009, Devons commitments included $1.4 billion that related to long-term
contracts for three deepwater drilling rigs. This total includes $1.2 billion related to two
contracts to be assumed by BP in connection with the associated divestiture transactions as
discussed in Note 5.
At the end of 2009, Devons commitments also included $0.4 billion that related to leases of
floating, production, storage and offloading facilities being used in the Gulf of Mexico, Brazil
and China. Devons commitments for these leases will be assumed by the buyers of Devons assets in
these locations when the associated divestiture transactions close.
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. Fair Value Measurements
The following tables provide carrying value and fair value measurement information for Devons
financial assets and liabilities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
|
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
|
|
|
|
|
|
Prices in |
|
Other |
|
Significant |
|
|
|
|
|
|
|
|
|
|
Active |
|
Observable |
|
Unobservable |
|
|
Carrying |
|
Total Fair |
|
Markets |
|
Inputs |
|
Inputs |
|
|
Amount |
|
Value |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
|
(In millions) |
March 31, 2010 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
659 |
|
|
$ |
659 |
|
|
$ |
|
|
|
$ |
659 |
|
|
$ |
|
|
Gas price collars |
|
$ |
35 |
|
|
$ |
35 |
|
|
$ |
|
|
|
$ |
35 |
|
|
$ |
|
|
Gas basis swaps |
|
$ |
(2 |
) |
|
$ |
(2 |
) |
|
$ |
|
|
|
$ |
(2 |
) |
|
$ |
|
|
Oil price collars |
|
$ |
(34 |
) |
|
$ |
(34 |
) |
|
$ |
|
|
|
$ |
(34 |
) |
|
$ |
|
|
Interest rate swaps |
|
$ |
169 |
|
|
$ |
169 |
|
|
$ |
|
|
|
$ |
169 |
|
|
$ |
|
|
Debt |
|
$ |
(6,085 |
) |
|
$ |
(6,985 |
) |
|
$ |
(240 |
) |
|
$ |
(6,745 |
) |
|
$ |
|
|
Long-term investments |
|
$ |
107 |
|
|
$ |
107 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
169 |
|
|
$ |
169 |
|
|
$ |
|
|
|
$ |
169 |
|
|
$ |
|
|
Gas basis swaps |
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
|
|
|
$ |
3 |
|
|
$ |
|
|
Oil price collars |
|
$ |
(38 |
) |
|
$ |
(38 |
) |
|
$ |
|
|
|
$ |
(38 |
) |
|
$ |
|
|
Interest rate swaps |
|
$ |
170 |
|
|
$ |
170 |
|
|
$ |
|
|
|
$ |
170 |
|
|
$ |
|
|
Debt |
|
$ |
(7,279 |
) |
|
$ |
(8,214 |
) |
|
$ |
(1,432 |
) |
|
$ |
(6,782 |
) |
|
$ |
|
|
Long-term investments |
|
$ |
115 |
|
|
$ |
115 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
115 |
|
14. Restructuring Costs
In the fourth quarter of 2009, Devon recognized $153 million of estimated employee severance
costs associated with the planned divestitures of its offshore assets that was announced in
November 2009. This amount was based on estimates of the number of employees that will ultimately
be impacted by the divestitures and includes $63 million related to accelerated vesting of
share-based grants. Of the $153 million total, $105 million relates to Devons U.S. Offshore
operations and the remainder relates to its International discontinued operations.
Devons estimate of employee severance costs recognized in the fourth quarter of 2009 was
based upon certain key estimates that could change as properties are sold. These estimates include
the number of impacted employees, the number of employees offered comparable positions with the
buyers and the date of separation for impacted employees. As discussed in Note 5, Devon has only
closed a limited number of divestiture transactions, which did not impact a significant number of
employees. As a result, Devon did not revise its estimate of employee severance costs during the
first quarter of 2010.
15. Reduction of Carrying Value of Oil and Gas Properties
In the first quarter of 2009, Devon reduced the carrying value of its United States oil and
gas properties $6.4 billion, or $4.1 billion after taxes, due to a full cost ceiling limitation.
The reduction resulted from a significant decrease in the full cost ceiling compared to the
immediately preceding quarter due to the effects of declining natural gas prices subsequent to
December 31, 2008.
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
16. Discontinued Operations
Revenues related to Devons discontinued operations totaled $212 million and $128 million in
the three months ended March 31, 2010 and March 31, 2009, respectively.
The following table presents the main classes of assets and liabilities associated with
Devons discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Cash and cash equivalents |
|
$ |
458 |
|
|
$ |
365 |
|
Accounts receivable |
|
|
122 |
|
|
|
165 |
|
Other current assets |
|
|
151 |
|
|
|
127 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
731 |
|
|
$ |
657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
1,260 |
|
|
$ |
1,099 |
|
Goodwill |
|
|
68 |
|
|
|
68 |
|
Other long-term assets |
|
|
81 |
|
|
|
83 |
|
|
|
|
|
|
|
|
Total long-term assets |
|
$ |
1,409 |
|
|
$ |
1,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
209 |
|
|
$ |
158 |
|
Other current liabilities |
|
|
94 |
|
|
|
76 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
303 |
|
|
$ |
234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
$ |
102 |
|
|
$ |
109 |
|
Deferred income taxes |
|
|
102 |
|
|
|
101 |
|
Other liabilities |
|
|
4 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
208 |
|
|
$ |
213 |
|
|
|
|
|
|
|
|
Reductions of Carrying Value of Oil and Gas Properties
In the first quarter of 2009, Devon reduced the carrying values of its Brazilian and other
International oil and gas properties, which are now held for sale, $109 million due to full cost
ceiling limitations. The Brazilian reduction of $103 million, which had no related tax benefit,
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.
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
17. Earnings (Loss) Per Share
The following table reconciles earnings (loss) from continuing operations and common shares
outstanding used in the calculations of basic and diluted earnings (loss) per share for the
three-month periods ended March 31, 2010 and 2009. Because a net loss from continuing operations
was generated during the three-month period ended March 31, 2009, the dilutive shares produce an
antidilutive net loss per share result. Therefore, the diluted loss per share from continuing
operations reported in the accompanying 2009 consolidated statement of operations is the same as
the basic loss per share amount.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings |
|
|
|
Earnings |
|
|
Common |
|
|
(Loss) |
|
|
|
(Loss) |
|
|
Shares |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,074 |
|
|
|
447 |
|
|
|
|
|
Attributable to participating securities |
|
|
(13 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
1,061 |
|
|
|
441 |
|
|
$ |
2.40 |
|
Dilutive effect of potential common shares issuable upon the exercise of outstanding stock options |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
1,061 |
|
|
|
443 |
|
|
$ |
2.39 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations |
|
$ |
(3,882 |
) |
|
|
444 |
|
|
|
|
|
Attributable to participating securities |
|
|
48 |
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share |
|
$ |
(3,834 |
) |
|
|
439 |
|
|
$ |
(8.74 |
) |
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. These excluded options totaled 1.7 million and
8.9 million during the three-month periods ended March 31, 2010 and 2009, respectively.
18. Segment Information
Devon manages its operations through seven distinct operating segments, or divisions, which
are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its
United States divisions into one reporting segment due to the similar nature of the business.
However, Devons Canadian and International divisions are reported as separate reporting segments
primarily due to significant differences in the respective regulatory environments.
Following is certain financial information regarding Devons reporting segments. The revenues
reported are all from external customers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
As of March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
1,955 |
|
|
$ |
1,062 |
|
|
$ |
731 |
|
|
$ |
3,748 |
|
Property and equipment, net |
|
|
12,750 |
|
|
|
6,062 |
|
|
|
|
|
|
|
18,812 |
|
Goodwill |
|
|
3,046 |
|
|
|
2,972 |
|
|
|
|
|
|
|
6,018 |
|
Other assets |
|
|
622 |
|
|
|
68 |
|
|
|
1,409 |
|
|
|
2,099 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
18,373 |
|
|
$ |
10,164 |
|
|
$ |
2,140 |
|
|
$ |
30,677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
2,171 |
|
|
$ |
634 |
|
|
$ |
303 |
|
|
$ |
3,108 |
|
Long-term debt |
|
|
2,864 |
|
|
|
2,981 |
|
|
|
|
|
|
|
5,845 |
|
Asset retirement obligations |
|
|
814 |
|
|
|
823 |
|
|
|
|
|
|
|
1,637 |
|
Other liabilities |
|
|
875 |
|
|
|
46 |
|
|
|
208 |
|
|
|
1,129 |
|
Deferred income taxes |
|
|
919 |
|
|
|
1,084 |
|
|
|
|
|
|
|
2,003 |
|
Stockholders equity |
|
|
10,730 |
|
|
|
4,596 |
|
|
|
1,629 |
|
|
|
16,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
18,373 |
|
|
$ |
10,164 |
|
|
$ |
2,140 |
|
|
$ |
30,677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
1,370 |
|
|
$ |
700 |
|
|
$ |
2,070 |
|
Net gain (loss) on oil and gas derivative financial instruments |
|
|
625 |
|
|
|
(5 |
) |
|
|
620 |
|
Marketing and midstream revenues |
|
|
496 |
|
|
|
34 |
|
|
|
530 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
2,491 |
|
|
|
729 |
|
|
|
3,220 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
224 |
|
|
|
190 |
|
|
|
414 |
|
Taxes other than income taxes |
|
|
90 |
|
|
|
11 |
|
|
|
101 |
|
Marketing and midstream operating costs and expenses |
|
|
369 |
|
|
|
28 |
|
|
|
397 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
261 |
|
|
|
165 |
|
|
|
426 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
56 |
|
|
|
7 |
|
|
|
63 |
|
Accretion of asset retirement obligations |
|
|
13 |
|
|
|
13 |
|
|
|
26 |
|
General and administrative expenses |
|
|
108 |
|
|
|
30 |
|
|
|
138 |
|
Interest expense |
|
|
30 |
|
|
|
56 |
|
|
|
86 |
|
Change in fair value of other financial instruments |
|
|
(15 |
) |
|
|
|
|
|
|
(15 |
) |
Other income, net |
|
|
(3 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,133 |
|
|
|
499 |
|
|
|
1,632 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
1,358 |
|
|
|
230 |
|
|
|
1,588 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
214 |
|
|
|
85 |
|
|
|
299 |
|
Deferred |
|
|
235 |
|
|
|
(20 |
) |
|
|
215 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
449 |
|
|
|
65 |
|
|
|
514 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
909 |
|
|
$ |
165 |
|
|
$ |
1,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
1,033 |
|
|
$ |
370 |
|
|
$ |
1,403 |
|
Revision of future asset retirement obligations |
|
|
83 |
|
|
|
122 |
|
|
|
205 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
1,116 |
|
|
$ |
492 |
|
|
$ |
1,608 |
|
|
|
|
|
|
|
|
|
|
|
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
938 |
|
|
$ |
437 |
|
|
$ |
1,375 |
|
Net gain on oil and gas derivative financial instruments |
|
|
154 |
|
|
|
|
|
|
|
154 |
|
Marketing and midstream revenues |
|
|
364 |
|
|
|
7 |
|
|
|
371 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,456 |
|
|
|
444 |
|
|
|
1,900 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
270 |
|
|
|
170 |
|
|
|
440 |
|
Taxes other than income taxes |
|
|
81 |
|
|
|
8 |
|
|
|
89 |
|
Marketing and midstream operating costs and expenses |
|
|
220 |
|
|
|
4 |
|
|
|
224 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
440 |
|
|
|
120 |
|
|
|
560 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
64 |
|
|
|
6 |
|
|
|
70 |
|
Accretion of asset retirement obligations |
|
|
14 |
|
|
|
9 |
|
|
|
23 |
|
General and administrative expenses |
|
|
135 |
|
|
|
28 |
|
|
|
163 |
|
Interest expense |
|
|
27 |
|
|
|
56 |
|
|
|
83 |
|
Change in fair value of other financial instruments |
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
Reduction of carrying value of oil and gas properties |
|
|
6,408 |
|
|
|
|
|
|
|
6,408 |
|
Other (income) expense, net |
|
|
(3 |
) |
|
|
10 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
7,651 |
|
|
|
411 |
|
|
|
8,062 |
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations before income
taxes |
|
|
(6,195 |
) |
|
|
33 |
|
|
|
(6,162 |
) |
Income tax (benefit) expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(10 |
) |
|
|
2 |
|
|
|
(8 |
) |
Deferred |
|
|
(2,279 |
) |
|
|
7 |
|
|
|
(2,272 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense |
|
|
(2,289 |
) |
|
|
9 |
|
|
|
(2,280 |
) |
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations |
|
$ |
(3,906 |
) |
|
$ |
24 |
|
|
$ |
(3,882 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
1,145 |
|
|
$ |
301 |
|
|
$ |
1,446 |
|
Revision of future asset retirement obligations |
|
|
37 |
|
|
|
(15 |
) |
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
1,182 |
|
|
$ |
286 |
|
|
$ |
1,468 |
|
|
|
|
|
|
|
|
|
|
|
19. Supplemental Information to Statements of Cash Flows
Information related to Devons cash flows is presented below.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Net decrease (increase) in working capital: |
|
|
|
|
|
|
|
|
(Increase) decrease in accounts receivable |
|
$ |
(78 |
) |
|
$ |
201 |
|
(Increase) decrease in other current assets |
|
|
(2 |
) |
|
|
194 |
|
Decrease in accounts payable |
|
|
(29 |
) |
|
|
(27 |
) |
Increase (decrease) in revenues and royalties due to others |
|
|
58 |
|
|
|
(115 |
) |
Increase (decrease) in income taxes payable |
|
|
269 |
|
|
|
(3 |
) |
Decrease in other current liabilities |
|
|
(168 |
) |
|
|
(122 |
) |
|
|
|
|
|
|
|
Net decrease in working capital |
|
$ |
50 |
|
|
$ |
128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data continuing and discontinued operations: |
|
|
|
|
|
|
|
|
Interest paid net of capitalized interest |
|
$ |
137 |
|
|
$ |
98 |
|
Income taxes paid (received) |
|
$ |
50 |
|
|
$ |
(177 |
) |
21
|
|
|
Item 2. |
|
Managements Discussion and Analysis of Financial Condition and Results of Operations |
The following discussion addresses material changes in our results of operations and capital
resources and uses for the three-month period ended March 31, 2010, compared to the three-month
period ended March 31, 2009, and in our financial condition and liquidity since December 31, 2009.
For information regarding our critical accounting policies and estimates, see our 2009 Annual
Report on Form 10-K under Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
Business Overview
Net earnings in the first three months of 2010 were $1.2 billion, or $2.66 per diluted share.
This compared to a net loss of $4.0 billion, or $8.92 per diluted share in the first three months
of 2009. Our first three months of 2009 earnings were negatively impacted by a $6.4 billion ($4.1
billion after tax) reduction of the carrying value of our United States oil and gas properties.
Excluding the reduction of carrying value, our 2010 first quarter earnings increased primarily due
to the effects of higher commodity prices, partially offset by a decrease in production.
Key measures of our performance for the first three months of 2010 compared to the first three
months of 2009 are summarized below:
|
|
|
The combined realized price without hedges for oil, gas and NGLs increased 58% to $37.07
per Boe. |
|
|
|
|
Oil and gas derivatives generated a net gain of $620 million and $154 million in the
first three months of 2010 and 2009, respectively. Included in these amounts were cash
receipts of $96 million and $118 million, respectively. |
|
|
|
|
Operating cash flow increased 43% to $1.5 billion. |
|
|
|
|
Production decreased 5% to 56 million Boe. |
|
|
|
|
Marketing and midstream operating profit decreased 9% to $133 million. |
|
|
|
|
Cash spent on capital expenditures was approximately $1.3 billion in the first quarter of
2010. |
Additionally, we have made significant progress toward completion of our offshore divestiture
program. Through April 2010, we had announced divestiture transactions of our oil and gas
properties in the Gulf of Mexico, Azerbaijan, Brazil and our producing Panyu field offshore China.
Furthermore, in connection with BPs acquisition of our Gulf of Mexico and Brazilian properties, BP
is also assuming our leases of the Seadrill West Sirius and Transocean Deepwater Discovery drilling
rigs for the duration of the contract terms. Through April 2010, we had closed the transactions
related to all our deepwater Gulf of Mexico properties. The divestiture process is ongoing for the
remaining announced transactions, as well as our exploration assets in China and Angola and other
minor International assets. We expect the closing of all divestitures to be completed by the end of
2010.
Our announced divestitures have proceeds that total $9.9 billion before taxes. Once all
divestiture assets are sold, we estimate the total pre-tax proceeds will exceed $10 billion and the
after-tax proceeds will be approximately $8 billion. As a result of the success we have experienced
with our offshore divestiture program, we announced a share repurchase program in early May 2010.
The program authorizes the repurchase of up to $3.5 billion of our common shares.
In conjunction with divestitures to BP, we also announced a heavy oil joint venture to operate
and develop BPs Kirby oil sands leases in Alberta, Canada. We will acquire 50 percent of BPs
interest in the Kirby oil sands leases for $500 million. We expect to close this transaction in the
second quarter of 2010. We will also fund $150 million of capital costs on BPs behalf. The
majority of these costs are expected to be paid during 2011 and 2012.
22
Results of Operations
Revenues
Our oil, gas and NGL production volumes are shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2010 |
|
2009 |
|
Change (2) |
Oil (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
3 |
|
|
|
3 |
|
|
|
0 |
% |
Canada |
|
|
7 |
|
|
|
6 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
North American Onshore |
|
|
10 |
|
|
|
9 |
|
|
|
0 |
% |
U.S. Offshore |
|
|
1 |
|
|
|
1 |
|
|
|
+6 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
11 |
|
|
|
10 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
166 |
|
|
|
181 |
|
|
|
-8 |
% |
Canada |
|
|
50 |
|
|
|
53 |
|
|
|
-4 |
% |
|
|
|
|
|
|
|
|
|
|
|
North American Onshore |
|
|
216 |
|
|
|
234 |
|
|
|
-7 |
% |
U.S. Offshore |
|
|
10 |
|
|
|
11 |
|
|
|
-8 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
226 |
|
|
|
245 |
|
|
|
-7 |
% |
|
|
|
|
|
|
|
|
|
|
|
NGLs (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
7 |
|
|
|
6 |
|
|
|
+6 |
% |
Canada |
|
|
1 |
|
|
|
1 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
|
North American Onshore |
|
|
8 |
|
|
|
7 |
|
|
|
+4 |
% |
U.S. Offshore |
|
|
|
|
|
|
|
|
|
|
-21 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
8 |
|
|
|
7 |
|
|
|
+3 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total (MMBoe) (1) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
37 |
|
|
|
40 |
|
|
|
-6 |
% |
Canada |
|
|
16 |
|
|
|
16 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
North American Onshore |
|
|
53 |
|
|
|
56 |
|
|
|
-5 |
% |
U.S. Offshore |
|
|
3 |
|
|
|
3 |
|
|
|
-4 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
56 |
|
|
|
59 |
|
|
|
-5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon
the approximate relative energy content of gas and oil, which rate is not necessarily
indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a
one-to-one basis with oil. |
|
(2) |
|
All percentage changes included in this table are based on actual figures and not the rounded
figures included in the table. |
23
The following table presents the prices we realized on our production volumes. These prices
exclude any effects due to our oil and gas derivative financial instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
2010 |
|
2009 |
|
Change |
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
74.81 |
|
|
$ |
34.88 |
|
|
|
+114 |
% |
Canada |
|
$ |
62.50 |
|
|
$ |
27.89 |
|
|
|
+124 |
% |
North American Onshore |
|
$ |
66.41 |
|
|
$ |
30.12 |
|
|
|
+120 |
% |
U.S. Offshore |
|
$ |
76.99 |
|
|
$ |
42.38 |
|
|
|
+82 |
% |
Total |
|
$ |
67.58 |
|
|
$ |
31.41 |
|
|
|
+115 |
% |
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
4.66 |
|
|
$ |
3.43 |
|
|
|
+36 |
% |
Canada |
|
$ |
5.08 |
|
|
$ |
4.48 |
|
|
|
+13 |
% |
North American Onshore |
|
$ |
4.76 |
|
|
$ |
3.67 |
|
|
|
+30 |
% |
U.S. Offshore |
|
$ |
5.63 |
|
|
$ |
5.15 |
|
|
|
+9 |
% |
Total |
|
$ |
4.80 |
|
|
$ |
3.73 |
|
|
|
+29 |
% |
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
34.22 |
|
|
$ |
17.43 |
|
|
|
+96 |
% |
Canada |
|
$ |
48.95 |
|
|
$ |
25.85 |
|
|
|
+89 |
% |
North American Onshore |
|
$ |
35.98 |
|
|
$ |
18.54 |
|
|
|
+94 |
% |
U.S. Offshore |
|
$ |
40.59 |
|
|
$ |
20.48 |
|
|
|
+98 |
% |
Total |
|
$ |
36.09 |
|
|
$ |
18.60 |
|
|
|
+94 |
% |
Combined (per Boe) (1) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
32.81 |
|
|
$ |
21.16 |
|
|
|
+55 |
% |
Canada |
|
$ |
44.50 |
|
|
$ |
27.21 |
|
|
|
+64 |
% |
North American Onshore |
|
$ |
36.29 |
|
|
$ |
22.92 |
|
|
|
+58 |
% |
U.S. Offshore |
|
$ |
51.07 |
|
|
$ |
34.21 |
|
|
|
+49 |
% |
Total |
|
$ |
37.07 |
|
|
$ |
23.51 |
|
|
|
+58 |
% |
|
|
|
(1) |
|
Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon
the approximate relative energy content of gas and oil, which rate is not necessarily
indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a
one-to-one basis with oil. |
The volume and price changes in the tables above caused the following changes to our oil, gas
and NGL sales between the three months ended March 31, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2009 sales |
|
$ |
327 |
|
|
$ |
912 |
|
|
$ |
136 |
|
|
$ |
1,375 |
|
Changes due to volumes |
|
|
3 |
|
|
|
(67 |
) |
|
|
5 |
|
|
|
(59 |
) |
Changes due to prices |
|
|
380 |
|
|
|
241 |
|
|
|
133 |
|
|
|
754 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 sales |
|
$ |
710 |
|
|
$ |
1,086 |
|
|
$ |
274 |
|
|
$ |
2,070 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales increased $380 million in the first three months of 2010 as a result of a 115%
increase in our realized price without hedges. The largest contributor to the increase in our
realized price was the increase in the average NYMEX West Texas Intermediate index price over the
same time period. In addition, our price differential based upon the NYMEX index price also
improved, which contributed to our higher realized price. The improved differential resulted
primarily from the tightening of the heavy oil differentials related to our Canadian operations.
Gas Sales
Gas sales increased $241 million during the first three months of 2010 as a result of a 29%
increase in our realized price without hedges. This increase was largely due to increases in the
North American regional index prices upon which our gas sales are based.
24
A 19 Bcf decrease in production during the first three months of 2010 caused gas sales to
decrease by $67 million. The decrease in production was primarily due to reduced drilling during
most of 2009 for our North American Onshore properties. As a result of the reduced drilling in
response to lower gas prices, natural declines of existing wells outpaced production gains from new
drilling.
NGL Sales
NGL sales increased $133 million during the first three months of 2010 as a result of a 94%
increase in our realized price without hedges. This increase was largely due to increases in the
regional index prices upon which our NGL sales are based.
Net Gain on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated with our oil and gas hedges. The
first table presents the cash settlements and unrealized gains and losses 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.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Cash settlement receipts (payments): |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
98 |
|
|
$ |
|
|
Gas price collars |
|
|
1 |
|
|
|
118 |
|
Gas basis swaps |
|
|
(3 |
) |
|
|
|
|
Oil price collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
96 |
|
|
|
118 |
|
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
490 |
|
|
|
|
|
Gas price collars |
|
|
35 |
|
|
|
36 |
|
Gas basis swaps |
|
|
(5 |
) |
|
|
|
|
Oil price collars |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains |
|
|
524 |
|
|
|
36 |
|
|
|
|
|
|
|
|
Net gain |
|
$ |
620 |
|
|
$ |
154 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
67.58 |
|
|
$ |
4.80 |
|
|
$ |
36.09 |
|
|
$ |
37.07 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.42 |
|
|
|
|
|
|
|
1.71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
67.58 |
|
|
$ |
5.22 |
|
|
$ |
36.09 |
|
|
$ |
38.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
31.41 |
|
|
$ |
3.73 |
|
|
$ |
18.60 |
|
|
$ |
23.51 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.48 |
|
|
|
|
|
|
|
2.02 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
31.41 |
|
|
$ |
4.21 |
|
|
$ |
18.60 |
|
|
$ |
25.53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In the first three months of 2010, our oil and gas derivative financial instruments included
gas price swaps, gas basis swaps and oil and gas costless price collars. In the first three months
of 2009, our oil and gas derivative financial instruments included only gas price collars. For the
price swaps, we receive a fixed price for our production and pay a variable market price to the
contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly
price indices are outside of the ranges set by the floor and ceiling prices in the various collars,
we cash-settle the difference with the counterparty to the collars. For the basis swaps, we receive
a fixed differential between two regional gas index prices and pay a variable differential on the
same two index prices to the contract counterparty. Cash settlements as presented in the tables
above represent realized gains or losses related to our price swaps, price collars and basis swaps.
25
During the first three months of 2010, we received $96 million, or $0.42 per Mcf from
counterparties to settle our gas derivatives. During the first three months of 2009, we received
$118 million, or $0.48 per Mcf, from counterparties to settle our gas derivatives.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes
in the fair values of our oil and gas derivative instruments in each reporting period. We estimate
the fair values of our oil and gas derivative financial instruments primarily by using internal
discounted cash flow calculations. From time to time, we validate our valuation techniques by
comparing our internally generated fair value estimates with those obtained from contract
counterparties or brokers.
The most significant variable to our cash flow calculations is our estimate of future
commodity prices. We base our estimate of future prices upon published forward commodity price
curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas
Intermediate forward curve for oil instruments. Based on the amount of volumes subject to our gas
derivatives at March 31, 2010, a 10% increase in these forward curves would have decreased the fair
value of our gas derivative financial instruments by approximately $159 million. A 10% increase in
the forward curves associated with our oil derivatives would have decreased the fair value of our
oil derivative financial instruments by approximately $75 million. Another key input to our cash
flow calculations is our estimate of volatility for these forward curves, which we base primarily
upon implied volatility.
Counterparty credit risk is also a component of commodity derivative valuations. We have
mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our
commodity derivative contracts are held with twelve separate counterparties. Additionally, our
derivative contracts generally require cash collateral to be posted if either our or the
counterpartys credit rating falls below investment grade. The threshold for collateral posting
decreases as the debt rating falls further below investment grade. Such thresholds generally range
from zero to $50 million for the majority of our contracts. As of March 31, 2010, the credit
ratings of all our counterparties were investment grade.
During the first three months of 2010 and 2009, the fair value of our commodity derivative
financial instruments increased by $524 million and $36 million, respectively. These unrealized
gains primarily resulted from decreases in the Inside FERC Henry Hub forward curve during the first
quarter of each year.
Marketing and Midstream Revenues and Operating Costs and Expenses
The details of the changes in marketing and midstream revenues, operating costs and expenses
and the resulting operating profit are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
|
|
|
|
Marketing and midstream: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
530 |
|
|
$ |
371 |
|
|
|
43 |
% |
Operating costs and expenses |
|
|
397 |
|
|
|
224 |
|
|
|
77 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
133 |
|
|
$ |
147 |
|
|
|
-9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
During the first three months of 2010, marketing and midstream revenues increased $159 million
and operating costs and expenses increased $173 million, causing operating profit to decrease $14
million. Revenues, expenses and operating profit increased due to higher natural gas and NGL
production and processing prices, partially offset by the effects of lower gas pipeline throughput.
However, the increase in operating profit resulting from these factors was more than offset by the
effect of lower prices realized from gas marketing activities.
26
Lease Operating Expenses (LOE)
The details of the changes in LOE are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
Lease operating expenses ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
191 |
|
|
$ |
229 |
|
|
|
-17 |
% |
Canada |
|
|
190 |
|
|
|
170 |
|
|
|
+12 |
% |
|
|
|
|
|
|
|
|
|
|
|
North American Onshore |
|
|
381 |
|
|
|
399 |
|
|
|
-5 |
% |
U.S. Offshore |
|
|
33 |
|
|
|
41 |
|
|
|
-19 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
414 |
|
|
$ |
440 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
5.12 |
|
|
$ |
5.82 |
|
|
|
-12 |
% |
Canada |
|
$ |
12.09 |
|
|
$ |
10.57 |
|
|
|
+14 |
% |
North American Onshore |
|
$ |
7.19 |
|
|
$ |
7.20 |
|
|
|
0 |
% |
U.S. Offshore |
|
$ |
11.18 |
|
|
$ |
13.33 |
|
|
|
-16 |
% |
Total |
|
$ |
7.41 |
|
|
$ |
7.52 |
|
|
|
-2 |
% |
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
LOE decreased $26 million in the first three months of 2010. LOE dropped $31 million due to
declining costs for fuel, materials, equipment and personnel, as well as declines in maintenance
and well workover projects. Such declines largely resulted from decreased demand for field
services. Our 5% decrease in production also reduced LOE by $20 million. Additionally, LOE
decreased $7 million due to additional costs incurred in the first three months of 2009 as a result
of hurricane damages sustained in 2008. These decreases were partially offset by changes in the
exchange rate between the U.S. and Canadian dollar which increased LOE by $32 million. Excluding
the decrease due to lower production, these factors were also the main contributors to the changes
in LOE per Boe.
Taxes Other Than Income Taxes
The following table details the changes in our taxes other than income taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
Production |
|
$ |
59 |
|
|
$ |
32 |
|
|
|
+83 |
% |
Ad valorem |
|
|
40 |
|
|
|
54 |
|
|
|
-27 |
% |
Other |
|
|
2 |
|
|
|
3 |
|
|
|
-36 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
101 |
|
|
$ |
89 |
|
|
|
+13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and not the rounded
figures included in this table. |
Production taxes increased $27 million in the first three months of 2010 primarily due to an
increase in our U.S. Onshore revenues. Ad valorem taxes decreased $14 million primarily due to
lower estimated assessed values of our oil and gas property and equipment.
27
Depreciation, Depletion and Amortization of Oil and Gas Properties (DD&A)
The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties
are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
Total production volumes (MMBoe) |
|
|
56 |
|
|
|
59 |
|
|
|
-5 |
% |
DD&A rate ($ per Boe) |
|
$ |
7.63 |
|
|
$ |
9.57 |
|
|
|
-20 |
% |
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
426 |
|
|
$ |
560 |
|
|
|
-24 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
The following table details the changes in DD&A of oil and gas properties between the three
months ended March 31, 2010 and 2009 (in millions).
|
|
|
|
|
2009 DD&A |
|
$ |
560 |
|
Change due to rate |
|
|
(108 |
) |
Change due to volumes |
|
|
(26 |
) |
|
|
|
|
2010 DD&A |
|
$ |
426 |
|
|
|
|
|
Oil and gas property-related DD&A decreased $108 million during the first three months of 2010
due to a 20% decrease in the DD&A rate. The largest contributor to the rate decrease was a
reduction of the carrying value of our United States oil and gas properties recognized in the first
quarter of 2009. This reduction totaled $6.4 billion and resulted from a full cost ceiling
limitation. Additionally, our drilling activities subsequent to the end of the first quarter of
2009 have resulted in proved reserve additions at a cost lower than the first quarter 2009 DD&A
rate, causing the rate to decrease. These decreases were partially offset by the effects of changes
in the exchange rate between the U.S. and Canadian dollar.
General and Administrative Expenses (G&A)
The following schedule includes the components of G&A expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
Change (1) |
|
|
|
(In millions) |
|
|
|
|
Gross G&A |
|
$ |
245 |
|
|
$ |
288 |
|
|
|
-15 |
% |
Capitalized G&A |
|
|
(80 |
) |
|
|
(90 |
) |
|
|
-11 |
% |
Reimbursed G&A |
|
|
(27 |
) |
|
|
(35 |
) |
|
|
-21 |
% |
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
138 |
|
|
$ |
163 |
|
|
|
-16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
Gross G&A decreased $43 million in the first three months of 2010 compared to the same period
in 2009. The largest contributor to the decrease was lower severance costs associated with employee
departures and other decreases in employee compensation and benefits. Also, gross G&A decreased as
a result of our initiatives to manage spending in certain discretionary cost categories. These
decreases were partially offset by the effects of changes in the exchange rate between the U.S. and
Canadian dollar. These factors were also the primary drivers of the decrease in capitalized G&A.
28
Change in Fair Value of Other Financial Instruments
The details of the changes in fair value of other financial instruments are shown in the table
below.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
(Gains) losses from interest rate swaps: |
|
|
|
|
|
|
|
|
Cash settlements |
|
$ |
(16 |
) |
|
$ |
(16 |
) |
Unrealized fair value changes |
|
|
1 |
|
|
|
11 |
|
|
|
|
|
|
|
|
Total |
|
$ |
(15 |
) |
|
$ |
(5 |
) |
|
|
|
|
|
|
|
Interest Rate Swaps
During the first three months of 2010 and 2009, we received cash settlements totaling $16
million from counterparties to settle our interest rate swaps.
In addition to recognizing cash settlements, we also recognize unrealized changes in the fair
values of our interest rate swaps each reporting period. In the first three months of 2010 and
2009, we recorded unrealized losses of $1 million and $11 million, respectively, as a result of
changes in interest rates.
We estimate the fair values of our interest rate swap financial instruments primarily by using
internal discounted cash flow calculations based upon forward interest-rate yields. We periodically
validate our valuation techniques by comparing our internally generated fair value estimates with
those obtained from contract counterparties or brokers.
The most significant variable to our cash flow calculation is our estimate of future interest
rate yields. We base our estimate of future yields upon our own internal model that utilizes
forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the
notional amounts subject to interest rate swaps at March 31, 2010, a 10% increase in these forward
curves would have increased the fair value of our interest rate swaps by approximately $50 million.
As previously discussed for our commodity derivative contracts, counterparty credit risk is
also a component of interest rate derivative valuations. We have mitigated our exposure to any
single counterparty by contracting with several counterparties. Our interest rate derivative
contracts are held with seven separate counterparties. Additionally, our derivative contracts
generally require cash collateral to be posted if either our or the counterpartys credit rating
falls below investment grade. The mark-to-market exposure threshold, above which collateral must be
posted, decreases as the debt rating falls further below investment grade. Such thresholds
generally range from zero to $50 million for the majority of our contracts. The credit ratings of
all our counterparties were investment grade as of March 31, 2010.
Reduction of Carrying Value of Oil and Gas Properties
In the first quarter of 2009, we reduced the carrying value of our United States oil and gas
properties by $6.4 billion, or $4.1 billion after taxes, due to a full cost ceiling limitation. The
reduction resulted from a significant decrease in the full cost ceiling compared to the immediately
preceding quarter due to the effects of declining natural gas prices subsequent to December 31,
2008.
29
Income Taxes
The following table presents our total income tax expense (benefit) and a reconciliation of
our effective income tax rate to the U.S. statutory income tax rate.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
Total income tax expense (benefit) (in millions) |
|
$ |
514 |
|
|
$ |
(2,280 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States statutory income tax rate |
|
|
35 |
% |
|
|
(35 |
%) |
State income taxes |
|
|
1 |
% |
|
|
(1 |
%) |
Taxation on Canadian operations |
|
|
(1 |
%) |
|
|
|
|
Other |
|
|
(3 |
%) |
|
|
(1 |
%) |
|
|
|
|
|
|
|
Effective income tax (benefit) rate |
|
|
32 |
% |
|
|
(37 |
%) |
|
|
|
|
|
|
|
Earnings (Loss) From Discontinued Operations
The following table presents the components of our earnings (loss) from discontinued
operations.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
Total production (MMBoe) |
|
|
3 |
|
|
|
3 |
|
Combined price without hedges (per Boe) |
|
$ |
72.65 |
|
|
$ |
40.68 |
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
Operating revenues |
|
$ |
212 |
|
|
$ |
128 |
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
Operating expenses |
|
|
78 |
|
|
|
86 |
|
Reduction of carrying value of oil and gas properties |
|
|
|
|
|
|
109 |
|
Other income |
|
|
(3 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
75 |
|
|
|
194 |
|
|
|
|
|
|
|
|
Earnings (loss) before income taxes |
|
|
137 |
|
|
|
(66 |
) |
Income tax expense |
|
|
19 |
|
|
|
11 |
|
|
|
|
|
|
|
|
Earnings (loss) from discontinued operations |
|
$ |
118 |
|
|
$ |
(77 |
) |
|
|
|
|
|
|
|
Earnings increased $195 million in the first three months of 2010 primarily as a result of two
factors. First, operating revenues increased largely due to a 79% increase in the price realized on
our production, which was driven by an increase in crude oil index prices.
Also, earnings increased $109 million due to 2009 reductions of the carrying values of our oil
and gas properties, which primarily related to Brazil. The Brazilian 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, we 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.
30
Capital Resources, Uses and Liquidity
The following discussion of capital resources and liquidity should be read in conjunction with
the consolidated statements of cash flows included in Part I, Item 1.
Sources and Uses of Cash
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
1,341 |
|
|
$ |
1,010 |
|
Commercial paper borrowings |
|
|
|
|
|
|
894 |
|
Debt issuance, net of commercial paper repayments |
|
|
|
|
|
|
182 |
|
Divestitures of property and equipment |
|
|
1,257 |
|
|
|
1 |
|
Stock option exercises |
|
|
8 |
|
|
|
4 |
|
Redemptions of long-term investments |
|
|
8 |
|
|
|
2 |
|
Other |
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
2,617 |
|
|
|
2,095 |
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(1,247 |
) |
|
|
(1,926 |
) |
Commercial paper repayments |
|
|
(1,192 |
) |
|
|
|
|
Debt repayments |
|
|
|
|
|
|
(1 |
) |
Dividends |
|
|
(72 |
) |
|
|
(70 |
) |
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(2,511 |
) |
|
|
(1,997 |
) |
|
|
|
|
|
|
|
Increase from continuing operations |
|
|
106 |
|
|
|
98 |
|
Increase (decrease) from discontinued operations |
|
|
47 |
|
|
|
(70 |
) |
Effect of foreign exchange rates |
|
|
18 |
|
|
|
(11 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
$ |
171 |
|
|
$ |
17 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
1,182 |
|
|
$ |
401 |
|
|
|
|
|
|
|
|
Operating Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash flow) continued to be a
significant source of capital and liquidity in the first three months of 2010. Changes in operating
cash flow are largely due to the same factors that affect our net earnings, with the exception of
those earnings changes due to noncash expenses such as DD&A, property impairments, financial
instrument fair value changes and deferred income taxes. Our operating cash flow increased
approximately 33% in 2010 primarily due to the increase in revenues as discussed in the Results of
Operations section of this report.
During the first three months of 2010, our operating cash flow was sufficient to fund our cash
payments for capital expenditures. During the first three months of 2009, our operating cash flow
funded approximately half of our cash payments for capital expenditures. Commercial paper and other
borrowings were used to fund the remainder of our cash-based capital expenditures.
Other Sources of Cash Continuing and Discontinued Operations
As needed, we supplement our operating cash flow and available cash by accessing available
credit under our credit facilities and commercial paper program. We may also issue long-term debt
to supplement our operating cash flow while maintaining adequate liquidity under our credit
facilities. Additionally, we may acquire short-term investments to maximize our income on available
cash balances. As needed, we reduce such short-term investment balances to further supplement our
operating cash flow and available cash.
During the first three months of 2010, we sold our interests in the Jack, St. Malo and Cascade
Lower Tertiary projects in the Gulf of Mexico for $1.3 billion. We used the proceeds from these
divestitures to repay commercial paper borrowings.
31
In January 2009, we 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 our $1.0 billion
of outstanding commercial paper as of December 31, 2008.
Subsequent to the $1.0 billion commercial paper repayment in January 2009, we utilized
additional commercial paper borrowings of $894 million to fund capital expenditures.
Capital Expenditures
Our capital expenditures are presented by geographic area and type in the following table. The
amounts in the table reflect cash payments for capital expenditures, including cash paid for
capital expenditures incurred in prior quarters. Capital expenditures actually incurred during the
first three months of 2010 and 2009 were approximately $1.6 billion and $1.5 billion, respectively.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
627 |
|
|
$ |
1,107 |
|
Canada |
|
|
377 |
|
|
|
327 |
|
|
|
|
|
|
|
|
North American Onshore |
|
|
1,004 |
|
|
|
1,434 |
|
U.S. Offshore |
|
|
126 |
|
|
|
333 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
1,130 |
|
|
|
1,767 |
|
Midstream |
|
|
48 |
|
|
|
128 |
|
Other |
|
|
69 |
|
|
|
31 |
|
|
|
|
|
|
|
|
Total continuing operations |
|
$ |
1,247 |
|
|
$ |
1,926 |
|
|
|
|
|
|
|
|
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 or development of oil and gas
properties, which totaled $1.1 billion and $1.8 billion in the first three months of 2010 and 2009,
respectively. The decrease in exploration and development capital spending in the first three
months of 2010 was primarily due to reduced drilling activities. Compared to the first quarter of
2009, we reduced drilling in response to lower commodity prices that were negatively impacting our
operating cash flow. With rising oil prices and proceeds from our offshore divestiture program, we
are increasing drilling to grow production across our North American Onshore portfolio of
properties.
Capital expenditures for our midstream operations are primarily for the construction and
expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. Our
midstream capital expenditures are largely impacted by oil and gas drilling activities. Therefore,
the reduction in development drilling also decreased midstream capital activities.
Net Repayments of Debt
During the first three months of 2010, we repaid $1.2 billion of commercial paper borrowings
primarily with proceeds received from Gulf of Mexico property divestitures.
Dividends
Our common stock dividends were $72 million and $70 million (quarterly rates of $0.16 per
share) in the first three months of 2010 and 2009, respectively.
Liquidity
Our primary source of capital and liquidity has historically been our operating cash flow.
Additionally, we maintain revolving lines of credit and a commercial paper program, which can be
accessed as needed to supplement operating cash flow. Other available sources of capital and
liquidity include equity and debt securities that can be issued pursuant to our automatically
effective shelf registration statement filed with the SEC. We estimate these capital resources and
the divestiture proceeds discussed below will provide sufficient liquidity to fund our planned uses
of capital. The following sections discuss changes to our liquidity subsequent to filing our 2009
Annual Report on Form 10-K.
32
Operating Cash Flow
Our operating cash flow increased approximately 43% to $1.5 billion in the first three months
of 2010. We expect operating cash flow to continue to be our primary source of liquidity. Our
operating cash flow is sensitive to many variables, the most volatile of which is pricing of the
oil, natural gas and NGLs produced. To mitigate some of the risk inherent in prices, we have
utilized various price collars to set minimum and maximum prices on a portion of our production. We
have also utilized various price swap contracts and fixed-price physical delivery contracts to fix
the price of a portion of our future natural gas production. As of March 31, 2010, approximately
56% of our estimated 2010 natural gas production and 69% of our estimated oil production are
subject to either price collars, swaps or fixed-price contracts.
Offshore Divestitures
During 2010, another major source of liquidity will be proceeds generated from divestitures of
our offshore assets. During the first quarter of 2010, we made significant progress toward
completion of our offshore divestiture program. In the first quarter of 2010, we closed the
divestitures of our interests in the Jack, St. Malo and Cascade Lower Tertiary projects in the
deepwater Gulf of Mexico for $1.3 billion ($1.1 billion after taxes).
In March 2010, we announced that we had entered into agreements to sell all of our remaining
assets in the deepwater Gulf of Mexico, Brazil and Azerbaijan to BP for $7.0 billion. In addition,
BP will assume our leases of the Seadrill West Sirius and Transocean Deepwater Discovery drilling
rigs for the duration of the contract terms. We closed the deepwater Gulf of Mexico transaction in
April 2010. We expect to close the Azerbaijan and Brazil transactions before the end of 2010.
In April 2010, we announced that we had entered into an agreement to sell all our
shallow-water Gulf of Mexico assets for $1.05 billion (approximately $840 million after taxes). We
expect to close this transaction in the second quarter of 2010.
Also in April 2010, we announced that we had entered into an agreement to sell our producing
Panyu field located offshore China for $515 million (approximately $370 million after taxes). We
expect to close this transaction in the second quarter of 2010.
Through April 2010, we have completely exited the deepwater Gulf of Mexico and announced
divestiture transactions with proceeds that total $9.9 billion before taxes. Once all divestiture
assets are sold, we estimate total pre-tax proceeds will exceed $10 billion and the after-tax
proceeds will be approximately $8 billion. We expect to use the offshore divestiture proceeds to
reduce debt, fund North American Onshore opportunities and repurchase shares of our common stock.
Credit Availability
In early May 2010, we cancelled our Short-Term Credit Facility prior to its November 2, 2010
maturity date. We incurred no cost to cancel the facility and will avoid paying the facility fee
that pertains to the cancellation period. As of May 3, 2010, excluding the Short-Term Credit
Facility, we had $2.6 billion of available capacity under our Senior Credit Facility that can be
used to supplement our operating cash flow and available cash to fund our capital expenditures and
other commitments. The following schedule summarizes the capacity of our Senior Credit Facility by
maturity date, as well as our available capacity as of May 3, 2010 (in millions).
|
|
|
|
|
Senior Credit Facility: |
|
|
|
|
April 7, 2012 maturity |
|
$ |
500 |
|
April 7, 2013 maturity |
|
|
2,150 |
|
|
|
|
|
Total Senior Credit Facility |
|
|
2,650 |
|
Less: |
|
|
|
|
Outstanding credit facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
|
|
Outstanding letters of credit |
|
|
88 |
|
|
|
|
|
Total available capacity |
|
$ |
2,562 |
|
|
|
|
|
The credit facility contains only one material financial covenant. This covenant requires us
to maintain a ratio of total funded debt to total capitalization, as defined in the credit
agreement, of no more than 65%. As of March 31, 2010, we were in compliance with this covenant. Our
debt-to-capitalization ratio at March 31, 2010, as calculated pursuant to the terms of the
agreement, was 17.1%.
33
In early May 2010, we reduced the maximum allowed borrowings under our commercial paper
program from $2.85 billion to approximately $2.2 billion.
Contractual Obligations
At the end of 2009, our commitments included $1.4 billion that related to long-term contracts
for three deepwater drilling rigs. This total includes $1.2 billion related to two contracts that
will be assumed by BP when the associated divestiture transactions close.
At the end of 2009, our commitments also included $0.4 billion that related to leases of
floating, production, storage and offloading facilities being used in the Gulf of Mexico, Brazil
and China. Our commitments for these leases will be assumed by the buyers of our assets in these
locations when the associated divestiture transactions close.
Common Share Repurchase Program
As a result of the success we have experienced with our offshore divestiture program, we
announced a share repurchase program in early May 2010. The program authorizes the repurchase of up
to $3.5 billion of our common shares.
|
|
|
Item 3. |
|
Quantitative and Qualitative Disclosures About Market Risk |
Commodity Price Risk
The key terms to all our oil and gas derivative financial instruments as of March 31, 2010 are
presented in the following tables.
|
|
|
|
|
|
|
|
|
|
|
2010 Gas Price Swaps |
|
|
|
|
|
|
Weighted |
|
|
Volume |
|
Average Price |
Period |
|
(MMBtu/d) |
|
($/MMBtu) |
Second quarter |
|
|
1,342,473 |
|
|
$ |
6.04 |
|
Third quarter |
|
|
1,265,000 |
|
|
$ |
6.16 |
|
Fourth quarter |
|
|
1,265,000 |
|
|
$ |
6.16 |
|
April December |
|
|
1,290,636 |
|
|
$ |
6.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Gas Price Collars |
|
|
|
|
|
|
Floor Price |
|
Ceiling Price |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Volume |
|
Floor Range |
|
Average Price |
|
Ceiling Range |
|
Average Price |
Period |
|
(MMBtu/d) |
|
($/MMBtu) |
|
($/MMBtu) |
|
($/MMBtu) |
|
($/MMBtu) |
April December |
|
|
95,000 |
|
|
$ |
5.50 $5.50 |
|
|
$ |
5.50 |
|
|
$ |
6.80 $7.10 |
|
|
$ |
6.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Gas Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
Differential to |
|
|
|
|
|
|
|
Volume |
|
|
Henry Hub |
|
Period |
|
Index |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
April December |
|
AECO |
|
|
150,000 |
|
|
$ |
0.33 |
|
April December |
|
CIG |
|
|
70,000 |
|
|
$ |
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 Oil Price Collars |
|
|
|
|
|
|
|
Floor Price |
|
|
Ceiling Price |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Floor Range |
|
|
Average Price |
|
|
Ceiling Range |
|
|
Average Price |
|
Period |
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
April December |
|
|
79,000 |
|
|
$ |
65.00 $70.00 |
|
|
$ |
67.47 |
|
|
$ |
90.35 $103.30 |
|
|
$ |
96.48 |
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 Oil Price Collars |
|
|
|
|
|
|
|
Floor Price |
|
|
Ceiling Price |
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Floor Range |
|
|
Average Price |
|
|
Ceiling Range |
|
|
Average Price |
|
Period |
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
Total year |
|
|
3,000 |
|
|
$ |
75.00 - $75.00 |
|
|
$ |
75.00 |
|
|
$ |
105.00 - $105.75 |
|
|
$ |
105.50 |
|
The fair values of our gas price swaps and collars and oil collars are largely determined by
estimates of the forward curves of relevant oil and gas price indexes. At March 31, 2010, a 10%
increase in the forward curves associated with our gas price swaps and collars would have decreased
the fair value of such instruments by approximately $159 million. A 10% increase in the forward
curves associated with our oil collars would have decreased the fair value of such instruments by
approximately $75 million.
Interest Rate Risk
At March 31, 2010, we had debt outstanding of $6.1 billion. Of this amount, $5.9 billion bears
interest at fixed rates averaging 7.2%. Additionally, we had $0.2 billion of outstanding commercial
paper, bearing interest at floating rates which averaged 0.22%.
The key terms of our interest rate derivative financial instruments as of March 31, 2010 are
presented in the following tables.
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-Floating Swaps |
|
|
|
|
|
Fixed Rate |
|
|
Variable |
|
|
|
Notional |
|
|
Received |
|
|
Rate Paid |
|
Expiration |
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
$ |
300 |
|
|
|
4.30 |
% |
|
Six month LIBOR |
|
July 18, 2011 |
|
100 |
|
|
|
1.90 |
% |
|
Federal funds rate |
|
August 3, 2012 |
|
500 |
|
|
|
3.90 |
% |
|
Federal funds rate |
|
July 18, 2013 |
|
250 |
|
|
|
3.85 |
% |
|
Federal funds rate |
|
July 22, 2013 |
|
|
|
|
|
|
|
|
|
|
$ |
1,150 |
|
|
|
3.82 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward Starting Swaps |
|
|
|
|
Fixed Rate |
|
Variable |
|
|
Notional |
|
Paid |
|
Rate Received |
|
Expiration |
(In millions) |
|
|
|
|
|
|
|
|
|
|
$ |
700 |
|
|
|
3.99 |
% |
|
Three month LIBOR |
|
September 30, 2011 |
The fair values of our interest rate instruments are largely determined by estimates of the
forward curves of the Federal Funds Rate and LIBOR. At March 31, 2010, a 10% increase in these
forward curves would have increased the fair value of our interest rate swaps by approximately
$50 million.
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 the average exchange rate during the reporting period. A 10% unfavorable change in the
Canadian-to-U.S. dollar exchange rate would not materially impact our March 31, 2010 balance sheet.
|
|
|
Item 4. |
|
Controls and Procedures |
Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information
relating to Devon, including its consolidated subsidiaries, is made known to the officers who
certify Devons financial reports and to other members of senior management and the Board of
Directors.
35
Based on their evaluation, Devons principal executive and principal financial officers have
concluded that Devons disclosure controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) under the Securities Exchange Act of 1934) were effective as of March 31, 2010 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 was no change in Devons internal control over financial reporting during the first
quarter of 2010 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
36
PART II. Other Information
|
|
|
Item 1. |
|
Legal Proceedings |
There have been no material changes to the information included in Item 3. Legal Proceedings
in our 2009 Annual Report on Form 10-K.
There have been no material changes to the information included in Item 1A. Risk Factors in
our 2009 Annual Report on Form 10-K.
|
|
|
Item 2. |
|
Unregistered Sales of Equity Securities and Use of Proceeds |
None.
|
|
|
Item 3. |
|
Defaults Upon Senior Securities |
None.
|
|
|
Item 5. |
|
Other Information |
None.
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
|
|
|
Exhibit |
|
|
Number |
|
Description |
31.1
|
|
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2
|
|
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS
|
|
XBRL Instance Document |
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document |
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document |
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document |
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document |
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document |
37
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
DEVON ENERGY CORPORATION
|
|
Date: May 6, 2010 |
/s/ Danny J. Heatly
|
|
|
Danny J. Heatly |
|
|
Senior Vice President Accounting and
Chief Accounting Officer |
|
|
38
INDEX TO EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Description |
31.1
|
|
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2
|
|
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS
|
|
XBRL Instance Document |
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document |
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document |
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document |
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document |
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document |