e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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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 September 30, 2010
or
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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 October 28, 2010, 431.9 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
For the Quarterly Period Ended September 30, 2010
INDEX
2
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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MMBoe means million Boe. |
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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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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 America 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. |
3
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, 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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public policy and government regulatory changes, including changes in royalty, production
tax and income tax regimes, changes in hydraulic fracturing regulation, changes in
environmental regulation and liability under federal, state, local or foreign environmental
laws and regulations; |
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terrorism; |
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occurrence, timing and completion of property acquisitions or divestitures; and |
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risk factors disclosed under Item 1A in our 2009 Annual Report on Form 10-K as well as
other factors disclosed under Item 2. Properties Proved Reserves and Estimated Future
Net Revenue, 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.
4
PART I. Financial Information
Item 1. Consolidated Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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September 30, |
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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) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
3,608 |
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$ |
646 |
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Accounts receivable |
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1,028 |
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1,208 |
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Current assets held for sale |
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576 |
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657 |
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Other current assets |
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738 |
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481 |
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Total current assets |
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5,950 |
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2,992 |
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Property and equipment, at cost: |
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Oil and gas, based on full cost accounting: |
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Subject to amortization |
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53,563 |
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52,352 |
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Not subject to amortization |
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3,605 |
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4,078 |
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Total oil and gas |
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57,168 |
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56,430 |
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Other |
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4,330 |
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4,045 |
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Total property and equipment, at cost |
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61,498 |
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60,475 |
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Less accumulated depreciation, depletion and amortization |
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(43,299 |
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(41,708 |
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Property and equipment, net |
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18,199 |
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18,767 |
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Goodwill |
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5,977 |
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5,930 |
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Long-term assets held for sale |
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875 |
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1,250 |
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Other long-term assets |
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862 |
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747 |
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Total assets |
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$ |
31,863 |
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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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$ |
1,192 |
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$ |
1,137 |
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Revenues and royalties due to others |
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517 |
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486 |
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Short-term debt |
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1,808 |
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1,432 |
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Current liabilities associated with assets held for sale |
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377 |
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234 |
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Other current liabilities |
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556 |
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513 |
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Total current liabilities |
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4,450 |
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3,802 |
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Long-term debt |
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3,821 |
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5,847 |
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Asset retirement obligations |
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1,394 |
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1,418 |
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Liabilities associated with assets held for sale |
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69 |
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213 |
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Other long-term liabilities |
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1,072 |
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937 |
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Deferred income taxes |
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2,405 |
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1,899 |
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Stockholders equity: |
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Common stock of $0.10 par value. Authorized 1.0 billion shares;
issued 432.2 million and 446.7 million shares in 2010 and
2009, respectively |
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43 |
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45 |
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Additional paid-in capital |
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5,714 |
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6,527 |
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Retained earnings |
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11,390 |
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7,613 |
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Accumulated other comprehensive earnings |
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1,512 |
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1,385 |
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Treasury stock, at cost. 0.1 million shares in 2010 |
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(7 |
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Total stockholders equity |
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18,652 |
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15,570 |
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Commitments and contingencies (Note 11) |
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Total liabilities and stockholders equity |
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$ |
31,863 |
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$ |
29,686 |
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See accompanying notes to consolidated financial statements.
5
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2010 |
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2009 |
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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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$ |
1,683 |
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$ |
1,481 |
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$ |
5,535 |
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$ |
4,306 |
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Oil, gas and NGL derivatives |
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209 |
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23 |
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874 |
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190 |
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Marketing and midstream revenues |
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461 |
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344 |
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1,396 |
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1,074 |
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Total revenues |
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2,353 |
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1,848 |
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7,805 |
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5,570 |
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Expenses and other, net: |
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Lease operating expenses |
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415 |
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416 |
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1,271 |
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1,266 |
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Taxes other than income taxes |
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95 |
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81 |
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288 |
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249 |
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Marketing and midstream operating costs and expenses |
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336 |
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241 |
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1,013 |
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695 |
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Depreciation, depletion and amortization of oil and gas properties |
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397 |
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424 |
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1,249 |
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1,414 |
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Depreciation and amortization of non-oil and gas properties |
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66 |
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64 |
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192 |
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208 |
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Accretion of asset retirement obligations |
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21 |
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22 |
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71 |
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68 |
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General and administrative expenses |
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131 |
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136 |
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399 |
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472 |
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Restructuring costs |
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63 |
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55 |
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Interest expense |
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83 |
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90 |
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280 |
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263 |
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Interest-rate and other financial instruments |
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55 |
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(5 |
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121 |
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(20 |
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Reduction of carrying value of oil and gas properties |
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6,408 |
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Other, net |
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(8 |
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(92 |
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(34 |
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(61 |
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Total expenses and other, net |
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1,654 |
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1,377 |
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4,905 |
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10,962 |
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Earnings (loss) from continuing operations before income taxes |
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699 |
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471 |
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2,900 |
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(5,392 |
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Income tax expense (benefit): |
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Current |
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(310 |
) |
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85 |
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696 |
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135 |
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Deferred |
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580 |
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4 |
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349 |
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(2,217 |
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Total income tax expense (benefit) |
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270 |
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89 |
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1,045 |
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(2,082 |
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Earnings (loss) from continuing operations |
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429 |
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382 |
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1,855 |
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(3,310 |
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Discontinued operations: |
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Earnings (loss) from discontinued operations before income taxes |
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1,710 |
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|
121 |
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2,320 |
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198 |
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Discontinued operations income tax expense |
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49 |
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4 |
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187 |
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34 |
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Earnings (loss) from discontinued operations |
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1,661 |
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|
117 |
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2,133 |
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|
164 |
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Net earnings (loss) |
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$ |
2,090 |
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$ |
499 |
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$ |
3,988 |
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$ |
(3,146 |
) |
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Basic earnings (loss) from continuing operations per share |
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$ |
0.99 |
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$ |
0.86 |
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$ |
4.20 |
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$ |
(7.46 |
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Basic earnings (loss) from discontinued operations per share |
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3.82 |
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0.27 |
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4.82 |
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0.37 |
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Basic net earnings (loss) per share |
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$ |
4.81 |
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$ |
1.13 |
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$ |
9.02 |
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$ |
(7.09 |
) |
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Diluted earnings (loss) from continuing operations per share |
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$ |
0.98 |
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$ |
0.86 |
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$ |
4.18 |
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$ |
(7.46 |
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Diluted earnings (loss) from discontinued operations per share |
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3.81 |
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0.26 |
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4.81 |
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0.37 |
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Diluted net earnings (loss) per share |
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$ |
4.79 |
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$ |
1.12 |
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$ |
8.99 |
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$ |
(7.09 |
) |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS (LOSS)
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Three Months Ended |
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Nine Months Ended |
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September 30, |
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September 30, |
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2010 |
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2009 |
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2010 |
|
|
2009 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Net earnings (loss) |
|
$ |
2,090 |
|
|
$ |
499 |
|
|
$ |
3,988 |
|
|
$ |
(3,146 |
) |
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment |
|
|
223 |
|
|
|
520 |
|
|
|
119 |
|
|
|
826 |
|
Foreign currency translation income tax expense |
|
|
(12 |
) |
|
|
(31 |
) |
|
|
(7 |
) |
|
|
(50 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation total |
|
|
211 |
|
|
|
489 |
|
|
|
112 |
|
|
|
776 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial loss and prior service cost in
earnings |
|
|
8 |
|
|
|
12 |
|
|
|
24 |
|
|
|
36 |
|
Pension and postretirement benefit plans income tax expense |
|
|
(3 |
) |
|
|
(5 |
) |
|
|
(9 |
) |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans total |
|
|
5 |
|
|
|
7 |
|
|
|
15 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive earnings (loss), net of tax |
|
|
216 |
|
|
|
496 |
|
|
|
127 |
|
|
|
799 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive earnings (loss) |
|
$ |
2,306 |
|
|
$ |
995 |
|
|
$ |
4,115 |
|
|
$ |
(2,347 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Total |
|
|
|
Common Stock |
|
|
Paid-In |
|
|
Retained |
|
|
Comprehensive |
|
|
Treasury |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Earnings |
|
|
Stock |
|
|
Equity |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Nine Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009 |
|
|
447 |
|
|
$ |
45 |
|
|
$ |
6,527 |
|
|
$ |
7,613 |
|
|
$ |
1,385 |
|
|
$ |
|
|
|
$ |
15,570 |
|
Net earnings (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,988 |
|
|
|
|
|
|
|
|
|
|
|
3,988 |
|
Other comprehensive earnings (loss), net
of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
127 |
|
|
|
|
|
|
|
127 |
|
Stock option exercises |
|
|
|
|
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(950 |
) |
|
|
(950 |
) |
Common stock retired |
|
|
(15 |
) |
|
|
(2 |
) |
|
|
(941 |
) |
|
|
|
|
|
|
|
|
|
|
943 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(211 |
) |
|
|
|
|
|
|
|
|
|
|
(211 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
103 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2010 |
|
|
432 |
|
|
$ |
43 |
|
|
$ |
5,714 |
|
|
$ |
11,390 |
|
|
$ |
1,512 |
|
|
$ |
(7 |
) |
|
$ |
18,652 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008 |
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,257 |
|
|
$ |
10,376 |
|
|
$ |
383 |
|
|
$ |
|
|
|
$ |
17,060 |
|
Net earnings (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,146 |
) |
|
|
|
|
|
|
|
|
|
|
(3,146 |
) |
Other comprehensive earnings (loss), net
of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
799 |
|
|
|
|
|
|
|
799 |
|
Stock option exercises |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12 |
) |
|
|
(12 |
) |
Common stock retired |
|
|
|
|
|
|
|
|
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(213 |
) |
|
|
|
|
|
|
|
|
|
|
(213 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
140 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2009 |
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,410 |
|
|
$ |
7,017 |
|
|
$ |
1,182 |
|
|
$ |
|
|
|
$ |
14,653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations |
|
$ |
1,855 |
|
|
$ |
(3,310 |
) |
Adjustments to reconcile earnings (loss) from continuing
operations to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
1,441 |
|
|
|
1,622 |
|
Deferred income tax expense (benefit) |
|
|
349 |
|
|
|
(2,217 |
) |
Reduction of carrying value of oil and gas properties |
|
|
|
|
|
|
6,408 |
|
Unrealized change in fair value of financial instruments |
|
|
(136 |
) |
|
|
184 |
|
Other noncash charges |
|
|
154 |
|
|
|
182 |
|
Net decrease in working capital |
|
|
164 |
|
|
|
81 |
|
Decrease in long-term other assets |
|
|
28 |
|
|
|
17 |
|
Increase (decrease) in long-term other liabilities |
|
|
57 |
|
|
|
(32 |
) |
|
|
|
|
|
|
|
Cash from operating activities continuing operations |
|
|
3,912 |
|
|
|
2,935 |
|
Cash from operating activities discontinued operations |
|
|
324 |
|
|
|
357 |
|
|
|
|
|
|
|
|
Net cash from operating activities |
|
|
4,236 |
|
|
|
3,292 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from property and equipment divestitures |
|
|
4,131 |
|
|
|
23 |
|
Capital expenditures |
|
|
(4,793 |
) |
|
|
(3,807 |
) |
Redemptions of long-term investments |
|
|
20 |
|
|
|
6 |
|
Other |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
Cash from investing activities continuing operations |
|
|
(655 |
) |
|
|
(3,778 |
) |
Cash from investing activities discontinued operations |
|
|
2,298 |
|
|
|
(376 |
) |
|
|
|
|
|
|
|
Net cash from investing activities |
|
|
1,643 |
|
|
|
(4,154 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from borrowings of long-term debt, net of issuance
costs |
|
|
|
|
|
|
1,187 |
|
Net commercial paper (repayments) borrowings |
|
|
(1,432 |
) |
|
|
363 |
|
Debt repayments |
|
|
(350 |
) |
|
|
(1 |
) |
Proceeds from stock option exercises |
|
|
18 |
|
|
|
19 |
|
Repurchases of common stock |
|
|
(929 |
) |
|
|
|
|
Dividends paid on common stock |
|
|
(211 |
) |
|
|
(213 |
) |
Excess tax benefits related to share-based compensation |
|
|
7 |
|
|
|
6 |
|
|
|
|
|
|
|
|
Net cash from financing activities |
|
|
(2,897 |
) |
|
|
1,361 |
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
5 |
|
|
|
29 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
2,987 |
|
|
|
528 |
|
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) |
|
$ |
3,998 |
|
|
$ |
912 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
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 September 30, 2010 and Devons results of operations and cash flows for
the three-month and nine-month periods ended September 30, 2010 and 2009.
2. Accounts Receivable
The components of accounts receivable include the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010 |
|
|
December 31, 2009 |
|
|
|
(In millions) |
|
Oil, gas and NGL sales |
|
$ |
612 |
|
|
$ |
752 |
|
Marketing and midstream revenues |
|
|
160 |
|
|
|
188 |
|
Joint interest billings |
|
|
158 |
|
|
|
151 |
|
Production tax credits |
|
|
85 |
|
|
|
110 |
|
Other |
|
|
22 |
|
|
|
19 |
|
|
|
|
|
|
|
|
Gross accounts receivable |
|
|
1,037 |
|
|
|
1,220 |
|
Allowance for doubtful accounts |
|
|
(9 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
Net accounts receivable |
|
$ |
1,028 |
|
|
$ |
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, gas
and NGL price volatility and to manage Devons exposure to interest rate volatility. Devon has
elected not to designate any of its derivative instruments for hedge accounting treatment.
The following table presents the derivative fair values included in the accompanying
consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Caption |
|
September 30, 2010 |
|
|
December 31, 2009 |
|
|
|
|
|
(In millions) |
|
Asset derivatives: |
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Other current assets |
|
$ |
493 |
|
|
$ |
172 |
|
Commodity derivatives |
|
Other long-term assets |
|
|
45 |
|
|
|
|
|
Interest rate derivatives |
|
Other current assets |
|
|
|
|
|
|
39 |
|
Interest rate derivatives |
|
Other long-term assets |
|
|
48 |
|
|
|
131 |
|
|
|
|
|
|
|
|
|
|
Total asset derivatives |
|
|
|
$ |
586 |
|
|
$ |
342 |
|
|
|
|
|
|
|
|
|
|
Liability derivatives: |
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Other current liabilities |
|
$ |
14 |
|
|
$ |
38 |
|
Commodity derivatives |
|
Other long-term liabilities |
|
|
96 |
|
|
|
|
|
Interest rate derivatives |
|
Other current liabilities |
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liability derivatives |
|
|
|
$ |
148 |
|
|
$ |
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. Cash settlements
and unrealized gains and losses on fair value changes associated with Devons commodity
derivatives are presented in the Oil,
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
gas and NGL derivatives caption in the accompanying
consolidated statements of operations. Cash settlements and unrealized gains and losses on fair
value changes associated with Devons interest rate derivatives are presented in the Interest-rate
and other financial instruments caption in the accompanying consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
232 |
|
|
$ |
127 |
|
|
$ |
580 |
|
|
$ |
359 |
|
Interest rate derivatives |
|
|
17 |
|
|
|
14 |
|
|
|
37 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
249 |
|
|
|
141 |
|
|
|
617 |
|
|
|
394 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
|
(23 |
) |
|
|
(104 |
) |
|
|
294 |
|
|
|
(169 |
) |
Interest rate derivatives |
|
|
(72 |
) |
|
|
(9 |
) |
|
|
(158 |
) |
|
|
(15 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) |
|
|
(95 |
) |
|
|
(113 |
) |
|
|
136 |
|
|
|
(184 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) recognized on
statement of operations |
|
$ |
154 |
|
|
$ |
28 |
|
|
$ |
753 |
|
|
$ |
210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4. Other Current Assets
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2010 |
|
|
December 31, 2009 |
|
|
|
(In millions) |
|
Derivative financial instruments |
|
$ |
493 |
|
|
$ |
211 |
|
Inventories |
|
|
141 |
|
|
|
182 |
|
Other |
|
|
104 |
|
|
|
88 |
|
|
|
|
|
|
|
|
Other current assets |
|
$ |
738 |
|
|
$ |
481 |
|
|
|
|
|
|
|
|
5. Property and Equipment
Offshore Divestitures
In November 2009, Devon announced plans to reposition itself strategically as a North America
onshore exploration and production company. As part of this strategic repositioning, Devon is
bringing forward the value of its offshore assets by divesting them.
Closed Transactions
The following table presents Devons offshore divestiture transactions that closed in the
first nine months of 2010. Gross proceeds represent contract prices based upon a January 1, 2010
effective date for the Gulf of Mexico and Azerbaijan divestitures, a May 1, 2010 effective date for
the China-Panyu divestiture, and a September 1, 2010 effective date for the China-Exploration
divestiture. After-tax proceeds represent gross proceeds adjusted for customary purchase price
adjustments, selling costs and income taxes. The purchase price adjustments consist primarily of
net cash flow subsequent to the effective date of the divestitures. Proved reserves in the
following table are based upon estimated proved reserves as of the divestiture dates.
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross Proceeds |
|
|
After-Tax Proceeds |
|
|
Proved Reserves |
|
|
|
(In millions) |
|
|
(MMBoe) |
|
|
|
|
|
|
|
|
|
|
|
(Unaudited) |
|
Gulf of Mexico (continuing operations) |
|
$ |
4,145 |
|
|
$ |
3,222 |
|
|
|
91 |
|
Azerbaijan (discontinued operations) |
|
|
2,000 |
|
|
|
1,924 |
|
|
|
56 |
|
China Panyu (discontinued operations) |
|
|
515 |
|
|
|
405 |
|
|
|
13 |
|
China Exploration (discontinued operations) |
|
|
77 |
|
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
6,737 |
|
|
$ |
5,610 |
|
|
|
160 |
|
|
|
|
|
|
|
|
|
|
|
Proceeds from these divestitures are being used to retire debt and repurchase Devon common
shares. Additionally, Devon is using divestiture proceeds to fund North America Onshore exploration
and development opportunities, including a joint-venture investment in the Pike oil sands discussed
below.
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 presented above did not significantly alter such relationship
for Devons United States cost center. Therefore, Devon did not recognize a gain in connection with
the Gulf of Mexico divestitures. The Azerbaijan divestiture included all of Devons properties in
its Azerbaijan cost center. As a result, Devon recognized a $1.5 billion ($1.5 billion after-tax)
gain during the third quarter of 2010 in connection with the Azerbaijan divestiture. Panyu was
Devons only producing property in its China cost center. As a result, Devon recognized a $308
million ($235 million after-tax) gain in connection with the Panyu divestiture in the second
quarter of 2010. No gain was recognized upon the divestiture of Devons exploratory assets in China
in the third quarter of 2010. These gains are included in earnings from discontinued operations
in the accompanying 2010 consolidated statements of operations.
Pending Transaction
Devon has entered into an agreement to sell its assets in Brazil for $3.2 billion. This
transaction continues to progress through the approval process of the Brazilian government and is
on track to close around the end of 2010. Devon expects to record a gain upon the close of the
transaction.
Deepwater Drilling Rigs
As part of its offshore operations, Devon was leasing three deepwater drilling rigs. The
Seadrill West Sirius and Ocean Endeavor deepwater drilling rigs were used in Devons Gulf of Mexico
operations. The Transocean Deepwater Discovery is being used in Devons operations in Brazil.
In conjunction with the deepwater Gulf of Mexico divestiture that closed in the second quarter
of 2010, the buyer assumed Devons lease and remaining commitments for the Seadrill West Sirius
rig. Subsequent to closing all its Gulf of Mexico divestitures, Devon agreed to pay $31 million to
the owner of the Ocean Endeavor rig to terminate the lease. The $31 million lease termination cost
is included in oil and gas property and equipment in the accompanying September 30, 2010,
consolidated balance sheet. The buyer of Devons assets in Brazil will assume Devons lease and
remaining commitments for the Transocean Deepwater Discovery rig when the divestiture transaction
closes.
Oil Sands Joint Venture
In conjunction with certain offshore divestitures in the second quarter of 2010, Devon formed
a heavy oil joint venture to operate and develop the Pike oil sands leases in Alberta, Canada. As a
result, Devon acquired a 50 percent interest in the Pike oil sands leases for $500 million. Devon
will also fund $155 million of Canadian dollar capital costs on behalf of its joint-venture partner
in the form of a non-interest bearing promissory note. The majority of the capital costs are
expected to be paid during 2011 and 2012. See Note 7 for more information regarding the promissory
note.
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
6. Goodwill
During the first nine months of 2010, Devons Canadian goodwill increased $47 million. This
increase was entirely due to foreign currency translation.
Devon removed all its International goodwill in conjunction with the Azerbaijan divestiture
that closed in the third quarter of 2010. Such goodwill totalled $68 million and was presented in
long-term assets held for sale in the accompanying December 31, 2009 consolidated balance sheet.
7. Debt
Commercial Paper
Devon repaid $1.4 billion of commercial paper borrowings during the first and second quarters
of 2010 primarily with proceeds received from its Gulf of Mexico property divestitures.
In May 2010, Devon reduced the maximum allowed borrowings under its commercial paper program
from $2.85 billion to approximately $2.2 billion. At September 30, 2010, Devon had no outstanding
commercial paper borrowings.
$350 Million 7.25% Senior Notes Due October 1, 2011
On June 25, 2010, Devon redeemed $350 million of 7.25% senior notes prior to their scheduled
maturity of October 1, 2011, primarily with proceeds received from its Gulf of Mexico divestitures.
The notes were redeemed for $384 million, which represented 100 percent of the principal amount, a
make-whole premium of $28 million and $6 million of accrued and unpaid interest. On the date of
redemption, these notes also had an unamortized premium of $9 million. The $28 million make-whole
premium and $9 million amortization of the remaining premium are included in interest expense in
the accompanying 2010 consolidated statements of operations.
Non-Interest Bearing Promissory Note
On June 29, 2010, Devon issued a four-year $155 million Canadian dollar non-interest bearing
promissory note in connection with the formation of the Pike oil sands joint venture described in
Note 5. The present value of the note was $139 million on the issue date based upon an effective
interest rate of 3.125%. At September 30, 2010, the note had a carrying value of $143 million, of
which $59 million is presented as short-term debt and the remainder is presented as long-term debt
in the accompanying consolidated balance sheet.
Credit Lines
In the second quarter of 2010, Devon cancelled its $700 million Short-Term Facility prior to
its November 2, 2010 maturity date. Devon incurred no cost to cancel the facility and will avoid
paying the facility fee that pertains to the cancellation period.
Devon has a syndicated, unsecured revolving line of credit that can be accessed to provide
liquidity as needed. The following schedule summarizes the capacity of Devons Senior Credit
Facility by maturity date, as well as its available capacity as of September 30, 2010 (in
millions).
|
|
|
|
|
April 7, 2012 maturity |
|
$ |
463 |
|
April 7, 2013 maturity |
|
|
2,187 |
|
|
|
|
|
Total Senior Credit Facility |
|
|
2,650 |
|
Less: |
|
|
|
|
Outstanding Senior Credit Facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
|
|
Outstanding letters of credit |
|
|
37 |
|
|
|
|
|
Total available capacity |
|
$ |
2,613 |
|
|
|
|
|
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The Senior Credit Facility contains 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 September 30, 2010, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at September 30, 2010, as calculated pursuant to the
terms of the agreement, was 15.3%.
Interest Expense
The following schedule includes the components of interest expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
98 |
|
|
$ |
112 |
|
|
$ |
307 |
|
|
$ |
330 |
|
Capitalized interest |
|
|
(20 |
) |
|
|
(22 |
) |
|
|
(55 |
) |
|
|
(71 |
) |
Early retirement of debt |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
|
|
Other |
|
|
5 |
|
|
|
|
|
|
|
9 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
83 |
|
|
$ |
90 |
|
|
$ |
280 |
|
|
$ |
263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8. Asset Retirement Obligations
The schedule below summarizes changes in Devons asset retirement obligations.
|
|
|
|
|
|
|
|
|
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Asset retirement obligations as of beginning of period |
|
$ |
1,513 |
|
|
$ |
1,387 |
|
Liabilities incurred |
|
|
36 |
|
|
|
50 |
|
Liabilities settled |
|
|
(94 |
) |
|
|
(75 |
) |
Revision of estimated obligation |
|
|
194 |
|
|
|
22 |
|
Liabilities assumed by others |
|
|
(256 |
) |
|
|
(17 |
) |
Accretion expense on discounted obligation |
|
|
71 |
|
|
|
68 |
|
Foreign currency translation adjustment |
|
|
10 |
|
|
|
82 |
|
|
|
|
|
|
|
|
Asset retirement obligations as of end of period |
|
|
1,474 |
|
|
|
1,517 |
|
Less current portion |
|
|
80 |
|
|
|
108 |
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term |
|
$ |
1,394 |
|
|
$ |
1,409 |
|
|
|
|
|
|
|
|
During the first nine months of 2010 and 2009, Devon recognized revisions to its asset
retirement obligations totaling $194 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.
During the first nine months of 2010, Devon reduced its continuing operations asset retirement
obligations by $256 million for those obligations that were assumed by purchasers of Devons Gulf
of Mexico oil and gas properties.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
9. Retirement Plans
The following table presents the components of net periodic benefit cost for Devons pension
and other post retirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Nine Months |
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
9 |
|
|
$ |
11 |
|
|
$ |
25 |
|
|
$ |
33 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
15 |
|
|
|
14 |
|
|
|
43 |
|
|
|
42 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
Expected return on plan assets |
|
|
(10 |
) |
|
|
(9 |
) |
|
|
(28 |
) |
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
|
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Net actuarial loss |
|
|
7 |
|
|
|
11 |
|
|
|
21 |
|
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
21 |
|
|
$ |
28 |
|
|
$ |
63 |
|
|
$ |
84 |
|
|
$ |
2 |
|
|
$ |
1 |
|
|
$ |
4 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10. Stockholders Equity
Stock Repurchases
During the first nine months of 2010, Devon repurchased 14.7 million common shares under its
$3.5 billion stock repurchase program for $936 million, or $63.61 per share. This program expires
December 31, 2011.
Dividends
Devon paid common stock dividends of $211 million and $213 million (quarterly rates of $0.16
per share) in the first nine months of 2010 and 2009, respectively.
11. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that
are probable of unfavorable outcome to Devon and that can be reasonably estimated are accrued. Such
accruals are based on information known about the matters, 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 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.
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 $0.9 billion that related to long-term lease
contracts for two deepwater drilling rigs being used in the Gulf of Mexico. As discussed in Note 5,
Devon no longer has lease commitments for these two rigs.
At the end of 2009, Devons commitments also included $0.5 billion that related to a long-term
lease contract for a deepwater drilling rig being used in Brazil. Devons lease and remaining
commitments for this rig will be assumed by the buyer of Devons assets in Brazil when the
associated divestiture transaction closes.
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 the Gulf of Mexico and China leases were assumed by the
purchasers in the first half of 2010. The Brazil lease will be assumed by the buyer when the
associated divestiture transaction closes.
12. 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) |
|
|
|
|
|
|
|
|
|
September 30, 2010 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
428 |
|
|
$ |
428 |
|
|
$ |
|
|
|
$ |
428 |
|
|
$ |
|
|
Interest rate derivatives |
|
$ |
10 |
|
|
$ |
10 |
|
|
$ |
|
|
|
$ |
10 |
|
|
$ |
|
|
Debt |
|
$ |
(5,629 |
) |
|
$ |
(6,747 |
) |
|
$ |
|
|
|
$ |
(6,604 |
) |
|
$ |
(143 |
) |
Long-term investments |
|
$ |
95 |
|
|
$ |
95 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
134 |
|
|
$ |
134 |
|
|
$ |
|
|
|
$ |
134 |
|
|
$ |
|
|
Interest rate derivatives |
|
$ |
170 |
|
|
$ |
170 |
|
|
$ |
|
|
|
$ |
170 |
|
|
$ |
|
|
Debt |
|
$ |
(7,279 |
) |
|
$ |
(8,214 |
) |
|
$ |
(1,432 |
) |
|
$ |
(6,782 |
) |
|
$ |
|
|
Long-term investments |
|
$ |
115 |
|
|
$ |
115 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
115 |
|
Devons Level 3 fair value measurements included in the table above relate to a non-interest
bearing promissory note and certain long-term investments. Included below is a summary of the
changes in Devons Level 3 fair value measurements during the first nine months of 2010 and 2009.
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term |
|
|
|
Debt |
|
|
Investments |
|
|
|
(In millions) |
|
December 31, 2009 |
|
$ |
|
|
|
$ |
115 |
|
Issuance of promissory note |
|
|
(139 |
) |
|
|
|
|
Foreign exchange translation adjustment |
|
|
(4 |
) |
|
|
|
|
Accretion of promissory note |
|
|
(1 |
) |
|
|
|
|
Redemptions of principal |
|
|
1 |
|
|
|
(20 |
) |
|
|
|
|
|
|
|
September 30, 2010 |
|
$ |
(143 |
) |
|
$ |
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008 |
|
$ |
|
|
|
$ |
122 |
|
Redemptions of principal |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
|
|
|
September 30, 2009 |
|
$ |
|
|
|
$ |
116 |
|
|
|
|
|
|
|
|
13. Restructuring Costs
Employee Severance
In the fourth quarter of 2009, Devon recognized $153 million of estimated employee severance
costs associated with the planned divestiture 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 included amounts related to cash severance costs and accelerated
vesting of share-based grants. Of the $153 million total, $105 million related to Devons U.S.
Offshore operations and the remainder related to its International discontinued operations.
As discussed in Note 5, Devon had divested all its U.S. Offshore assets by the end of the
second quarter of 2010 and a significant part of its International assets by the end of the third
quarter of 2010. As a result of these divestitures and associated employee terminations, Devon
decreased its estimate of employee severance costs in the second and third quarters of 2010 by $14
million and $21 million, respectively. As a result, Devon now estimates it will incur approximately
$118 million of employee severance costs. The lower estimate results primarily from more offshore
employees than previously estimated receiving comparable positions with the purchaser of the
properties or in Devons U.S. Onshore operations. Of the $118 million total, $78 million relates to
Devons U.S. Offshore operations and the remainder relates to its International discontinued
operations. Of the $35 million reduction recognized during 2010, $27 million relates to Devons
U.S. Offshore operations and the remainder relates to its International discontinued operations.
Lease Obligations
As a result of the divestitures discussed above, Devon ceased using certain office space that
was subject to non-cancellable operating lease arrangements. Consequently, in the third quarter of
2010, Devon recognized $70 million of restructuring costs that represent the present value of its
future obligations under the leases, net of anticipated sublease income. Devons estimate of lease
obligations was based upon certain key estimates that could change over the term of the leases.
These estimates include the estimated sublease income that Devon may receive over the term of the
leases, as well as the amount of variable operating costs that Devon will be required to pay under
the leases.
Asset Impairments
In the third quarter of 2010, Devon recognized $11 million of asset impairment charges for
leasehold improvements and furniture associated with the office space it ceased using.
Financial Statement Presentation
Recognition and adjustments to cash severance, accelerated vesting of share-based grants,
lease obligations and asset impairments are included in restructuring costs in the accompanying
2010 consolidated statements of operations. Amounts related to cash severance and lease obligations
are accrued for in other current liabilities and other long-term liabilities in the
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
accompanying consolidated balance sheets, while amounts related to accelerated share-based
awards are recorded as a reduction to Devons additional paid-in capital in the accompanying
consolidated balance sheets. Asset impairments are presented as a reduction to Devons net property
and equipment in the accompanying consolidated 2010 balance sheet.
The schedule below summarizes activity and balances associated with Devons restructuring
liabilities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Current Liabilities |
|
|
Other Long-Term Liabilities |
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
|
(In millions) |
|
Balance as of December 31, 2009 |
|
$ |
61 |
|
|
$ |
23 |
|
|
$ |
84 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Lease obligations incurred |
|
|
17 |
|
|
|
|
|
|
|
17 |
|
|
|
53 |
|
|
|
|
|
|
|
53 |
|
Cash severance paid |
|
|
(17 |
) |
|
|
(3 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash severance revision |
|
|
(18 |
) |
|
|
(5 |
) |
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2010 |
|
$ |
43 |
|
|
$ |
15 |
|
|
$ |
58 |
|
|
$ |
53 |
|
|
$ |
|
|
|
$ |
53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The schedule below summarizes the components of restructuring costs in the accompanying
consolidated statements of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, 2010 |
|
|
September 30, 2010 |
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
|
(In millions) |
|
Cash severance |
|
$ |
(13 |
) |
|
$ |
(1 |
) |
|
$ |
(14 |
) |
|
$ |
(18 |
) |
|
$ |
(4 |
) |
|
$ |
(22 |
) |
Share-based awards |
|
|
(5 |
) |
|
|
(2 |
) |
|
|
(7 |
) |
|
|
(9 |
) |
|
|
(4 |
) |
|
|
(13 |
) |
Lease obligations |
|
|
70 |
|
|
|
|
|
|
|
70 |
|
|
|
70 |
|
|
|
|
|
|
|
70 |
|
Asset impairments |
|
|
11 |
|
|
|
|
|
|
|
11 |
|
|
|
11 |
|
|
|
|
|
|
|
11 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring costs |
|
$ |
63 |
|
|
$ |
(3 |
) |
|
$ |
60 |
|
|
$ |
55 |
|
|
$ |
(8 |
) |
|
$ |
47 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14. 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 $6,408 million, or $4,085 million 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.
15. Income Taxes
The Gulf of Mexico divestitures discussed in Note 5 have taxable gains that increase Devons
current income tax expense of $858 million. However, the additional current income taxes are offset
by a decrease in deferred income tax expense, resulting in no impact to Devons total income tax
expense.
Additionally, in conjunction with the filing of its 2009 income tax return in the third
quarter of 2010, Devon recognized a $220 million decrease to current income tax expense that was
offset by a like increase to deferred income tax expense. These amounts relate to a change in the
timing of certain deductions which Devon elected to expense rather than capitalize for the 2009 tax
year. Such deductions created a net operating loss for the 2009 tax year that Devon is using to
reduce its 2010 current income taxes that would otherwise be due as a result of the taxable
divestiture gains mentioned above.
In the third quarter of 2009, Devon recognized $59 million of income tax benefits in
conjunction with the initial or amended filings of its 2005, 2006, 2007 and 2008 income tax
returns. These tax benefits consist of deferred tax benefits of $50 million and current tax
benefits of $9 million. Of the $59 million, $41 million relates to taxation on foreign operations.
The remaining $18 million relates to taxation on U.S. federal and state operations.
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
16. Discontinued Operations
Revenues related to Devons discontinued operations totaled $139 million and $573 million in
the third quarter and first nine months of 2010, respectively, and $250 million and $646 million in
the third quarter and first nine months of 2009, respectively.
The following table presents the main classes of assets and liabilities associated with
Devons discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Cash and cash equivalents |
|
$ |
390 |
|
|
$ |
365 |
|
Accounts receivable |
|
|
49 |
|
|
|
165 |
|
Other current assets |
|
|
137 |
|
|
|
127 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
576 |
|
|
$ |
657 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
816 |
|
|
$ |
1,099 |
|
Goodwill |
|
|
|
|
|
|
68 |
|
Other long-term assets |
|
|
59 |
|
|
|
83 |
|
|
|
|
|
|
|
|
Total long-term assets |
|
$ |
875 |
|
|
$ |
1,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
324 |
|
|
$ |
158 |
|
Other current liabilities |
|
|
53 |
|
|
|
76 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
377 |
|
|
$ |
234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations |
|
$ |
29 |
|
|
$ |
109 |
|
Deferred income taxes |
|
|
35 |
|
|
|
101 |
|
Other liabilities |
|
|
5 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
69 |
|
|
$ |
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.
Divestitures
See Note 5 for more information on the Azerbaijan and China divestitures.
19
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 and nine-month periods ended September 30, 2010 and 2009. Because a net loss from
continuing operations was generated during the nine-month period ended September 30, 2009, the
dilutive shares produce an antidilutive net loss per share result. Therefore, the diluted loss per
share amount from continuing operations in the nine months ended September 30, 2009 reported in the
accompanying 2009 consolidated statement of operations is the same as the basic loss per share
amount.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (Loss) |
|
|
|
Earnings (Loss) |
|
|
Common Shares |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
429 |
|
|
|
435 |
|
|
|
|
|
Attributable to participating securities |
|
|
(4 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
425 |
|
|
|
430 |
|
|
$ |
0.99 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
425 |
|
|
|
431 |
|
|
$ |
0.98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
382 |
|
|
|
444 |
|
|
|
|
|
Attributable to participating securities |
|
|
(4 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
378 |
|
|
|
439 |
|
|
$ |
0.86 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
378 |
|
|
|
441 |
|
|
$ |
0.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,855 |
|
|
|
442 |
|
|
|
|
|
Attributable to participating securities |
|
|
(21 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
1,834 |
|
|
|
437 |
|
|
$ |
4.20 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
1,834 |
|
|
|
439 |
|
|
$ |
4.18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations |
|
$ |
(3,310 |
) |
|
|
444 |
|
|
|
|
|
Attributable to participating securities |
|
|
36 |
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share |
|
$ |
(3,274 |
) |
|
|
439 |
|
|
$ |
(7.46 |
) |
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. During the three-month and nine-month periods
ended September 30, 2010, 8.6 million shares and 7.9 million shares, respectively, were excluded
from the diluted earnings per share calculations. During the three-month and nine-month periods
ended September 30, 2009, 7.1 million shares and 8.9 million shares, respectively, were excluded
from the diluted earnings per share calculations.
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
18. Segment Information
Devon manages its operations through distinct operating segments, or divisions, which are
defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its
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 September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
2,299 |
|
|
$ |
3,075 |
|
|
$ |
576 |
|
|
$ |
5,950 |
|
Property and equipment, net |
|
|
11,509 |
|
|
|
6,690 |
|
|
|
|
|
|
|
18,199 |
|
Goodwill |
|
|
3,046 |
|
|
|
2,931 |
|
|
|
|
|
|
|
5,977 |
|
Other assets |
|
|
517 |
|
|
|
345 |
|
|
|
875 |
|
|
|
1,737 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
17,371 |
|
|
$ |
13,041 |
|
|
$ |
1,451 |
|
|
$ |
31,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
1,578 |
|
|
$ |
2,495 |
|
|
$ |
377 |
|
|
$ |
4,450 |
|
Long-term debt |
|
|
2,503 |
|
|
|
1,318 |
|
|
|
|
|
|
|
3,821 |
|
Asset retirement obligations |
|
|
564 |
|
|
|
830 |
|
|
|
|
|
|
|
1,394 |
|
Other liabilities |
|
|
1,025 |
|
|
|
47 |
|
|
|
69 |
|
|
|
1,141 |
|
Deferred income taxes |
|
|
1,240 |
|
|
|
1,165 |
|
|
|
|
|
|
|
2,405 |
|
Stockholders equity |
|
|
10,461 |
|
|
|
7,186 |
|
|
|
1,005 |
|
|
|
18,652 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
17,371 |
|
|
$ |
13,041 |
|
|
$ |
1,451 |
|
|
$ |
31,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
1,104 |
|
|
$ |
579 |
|
|
$ |
1,683 |
|
Oil, gas and NGL derivatives |
|
|
214 |
|
|
|
(5 |
) |
|
|
209 |
|
Marketing and midstream revenues |
|
|
432 |
|
|
|
29 |
|
|
|
461 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,750 |
|
|
|
603 |
|
|
|
2,353 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
208 |
|
|
|
207 |
|
|
|
415 |
|
Taxes other than income taxes |
|
|
85 |
|
|
|
10 |
|
|
|
95 |
|
Marketing and midstream operating costs and expenses |
|
|
314 |
|
|
|
22 |
|
|
|
336 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
234 |
|
|
|
163 |
|
|
|
397 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
60 |
|
|
|
6 |
|
|
|
66 |
|
Accretion of asset retirement obligations |
|
|
8 |
|
|
|
13 |
|
|
|
21 |
|
General and administrative expenses |
|
|
97 |
|
|
|
34 |
|
|
|
131 |
|
Restructuring costs |
|
|
63 |
|
|
|
|
|
|
|
63 |
|
Interest expense |
|
|
36 |
|
|
|
47 |
|
|
|
83 |
|
Interest-rate and other financial instruments |
|
|
55 |
|
|
|
|
|
|
|
55 |
|
Other, net |
|
|
(7 |
) |
|
|
(1 |
) |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
1,153 |
|
|
|
501 |
|
|
|
1,654 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
597 |
|
|
|
102 |
|
|
|
699 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(349 |
) |
|
|
39 |
|
|
|
(310 |
) |
Deferred |
|
|
590 |
|
|
|
(10 |
) |
|
|
580 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
241 |
|
|
|
29 |
|
|
|
270 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
356 |
|
|
$ |
73 |
|
|
$ |
429 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,358 |
|
|
$ |
308 |
|
|
$ |
1,666 |
|
|
|
|
|
|
|
|
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
961 |
|
|
$ |
520 |
|
|
$ |
1,481 |
|
Oil, gas and NGL derivatives |
|
|
23 |
|
|
|
|
|
|
|
23 |
|
Marketing and midstream revenues |
|
|
333 |
|
|
|
11 |
|
|
|
344 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,317 |
|
|
|
531 |
|
|
|
1,848 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
244 |
|
|
|
172 |
|
|
|
416 |
|
Taxes other than income taxes |
|
|
72 |
|
|
|
9 |
|
|
|
81 |
|
Marketing and midstream operating costs and expenses |
|
|
236 |
|
|
|
5 |
|
|
|
241 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
270 |
|
|
|
154 |
|
|
|
424 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
58 |
|
|
|
6 |
|
|
|
64 |
|
Accretion of asset retirement obligations |
|
|
12 |
|
|
|
10 |
|
|
|
22 |
|
General and administrative expenses |
|
|
108 |
|
|
|
28 |
|
|
|
136 |
|
Interest expense |
|
|
34 |
|
|
|
56 |
|
|
|
90 |
|
Interest-rate and other financial instruments |
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
Other, net |
|
|
(99 |
) |
|
|
7 |
|
|
|
(92 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
930 |
|
|
|
447 |
|
|
|
1,377 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
387 |
|
|
|
84 |
|
|
|
471 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
27 |
|
|
|
58 |
|
|
|
85 |
|
Deferred |
|
|
30 |
|
|
|
(26 |
) |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
57 |
|
|
|
32 |
|
|
|
89 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
330 |
|
|
$ |
52 |
|
|
$ |
382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
696 |
|
|
$ |
247 |
|
|
$ |
943 |
|
|
|
|
|
|
|
|
|
|
|
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Nine Months Ended September 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
3,618 |
|
|
$ |
1,917 |
|
|
$ |
5,535 |
|
Oil, gas and NGL derivatives |
|
|
871 |
|
|
|
3 |
|
|
|
874 |
|
Marketing and midstream revenues |
|
|
1,300 |
|
|
|
96 |
|
|
|
1,396 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
5,789 |
|
|
|
2,016 |
|
|
|
7,805 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
675 |
|
|
|
596 |
|
|
|
1,271 |
|
Taxes other than income taxes |
|
|
258 |
|
|
|
30 |
|
|
|
288 |
|
Marketing and midstream operating costs and expenses |
|
|
935 |
|
|
|
78 |
|
|
|
1,013 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
743 |
|
|
|
506 |
|
|
|
1,249 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
173 |
|
|
|
19 |
|
|
|
192 |
|
Accretion of asset retirement obligations |
|
|
33 |
|
|
|
38 |
|
|
|
71 |
|
General and administrative expenses |
|
|
303 |
|
|
|
96 |
|
|
|
399 |
|
Restructuring costs |
|
|
55 |
|
|
|
|
|
|
|
55 |
|
Interest expense |
|
|
121 |
|
|
|
159 |
|
|
|
280 |
|
Interest-rate and other financial instruments |
|
|
121 |
|
|
|
|
|
|
|
121 |
|
Other, net |
|
|
(36 |
) |
|
|
2 |
|
|
|
(34 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
3,381 |
|
|
|
1,524 |
|
|
|
4,905 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
2,408 |
|
|
|
492 |
|
|
|
2,900 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
496 |
|
|
|
200 |
|
|
|
696 |
|
Deferred |
|
|
404 |
|
|
|
(55 |
) |
|
|
349 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
900 |
|
|
|
145 |
|
|
|
1,045 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,508 |
|
|
$ |
347 |
|
|
$ |
1,855 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset retirement
obligations |
|
$ |
3,547 |
|
|
$ |
1,452 |
|
|
$ |
4,999 |
|
Revision of future asset retirement obligations |
|
|
72 |
|
|
|
122 |
|
|
|
194 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
3,619 |
|
|
$ |
1,574 |
|
|
$ |
5,193 |
|
|
|
|
|
|
|
|
|
|
|
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Nine Months Ended September 30, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
2,806 |
|
|
$ |
1,500 |
|
|
$ |
4,306 |
|
Oil, gas and NGL derivatives |
|
|
190 |
|
|
|
|
|
|
|
190 |
|
Marketing and midstream revenues |
|
|
1,048 |
|
|
|
26 |
|
|
|
1,074 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
4,044 |
|
|
|
1,526 |
|
|
|
5,570 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
766 |
|
|
|
500 |
|
|
|
1,266 |
|
Taxes other than income taxes |
|
|
223 |
|
|
|
26 |
|
|
|
249 |
|
Marketing and midstream operating costs and expenses |
|
|
682 |
|
|
|
13 |
|
|
|
695 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
984 |
|
|
|
430 |
|
|
|
1,414 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
189 |
|
|
|
19 |
|
|
|
208 |
|
Accretion of asset retirement obligations |
|
|
40 |
|
|
|
28 |
|
|
|
68 |
|
General and administrative expenses |
|
|
384 |
|
|
|
88 |
|
|
|
472 |
|
Interest expense |
|
|
95 |
|
|
|
168 |
|
|
|
263 |
|
Interest-rate and other financial instruments |
|
|
(20 |
) |
|
|
|
|
|
|
(20 |
) |
Reduction of carrying value of oil and gas properties |
|
|
6,408 |
|
|
|
|
|
|
|
6,408 |
|
Other, net |
|
|
(84 |
) |
|
|
23 |
|
|
|
(61 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
9,667 |
|
|
|
1,295 |
|
|
|
10,962 |
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations before income
taxes |
|
|
(5,623 |
) |
|
|
231 |
|
|
|
(5,392 |
) |
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
31 |
|
|
|
104 |
|
|
|
135 |
|
Deferred |
|
|
(2,194 |
) |
|
|
(23 |
) |
|
|
(2,217 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense (benefit) |
|
|
(2,163 |
) |
|
|
81 |
|
|
|
(2,082 |
) |
|
|
|
|
|
|
|
|
|
|
Earnings (loss) from continuing operations |
|
$ |
(3,460 |
) |
|
$ |
150 |
|
|
$ |
(3,310 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
2,598 |
|
|
$ |
733 |
|
|
$ |
3,331 |
|
Revision of future asset retirement obligations |
|
|
37 |
|
|
|
(15 |
) |
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
2,635 |
|
|
$ |
718 |
|
|
$ |
3,353 |
|
|
|
|
|
|
|
|
|
|
|
19. Supplemental Information to Statements of Cash Flows
Information related to Devons cash flows is presented below.
|
|
|
|
|
|
|
|
|
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Net (increase) decrease in working capital: |
|
|
|
|
|
|
|
|
Decrease in accounts receivable |
|
$ |
185 |
|
|
$ |
285 |
|
Decrease in other current assets |
|
|
11 |
|
|
|
171 |
|
Increase (decrease) in accounts payable |
|
|
49 |
|
|
|
(50 |
) |
Increase (decrease) in revenues and royalties due to others |
|
|
29 |
|
|
|
(124 |
) |
Decrease in other current liabilities |
|
|
(110 |
) |
|
|
(201 |
) |
|
|
|
|
|
|
|
Net decrease in working capital |
|
$ |
164 |
|
|
$ |
81 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data continuing and discontinued operations: |
|
|
|
|
|
|
|
|
Interest paid net of capitalized interest |
|
$ |
338 |
|
|
$ |
273 |
|
Income taxes paid (received) |
|
$ |
745 |
|
|
$ |
(29 |
) |
25
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 and nine-month periods ended September 30, 2010, compared to
the three-month and nine-month periods ended September 30, 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.
Financial Overview
During the third quarter and first nine months of 2010, we generated net earnings of $2.1
billion, or $4.79 per diluted share, and $4.0 billion, or $8.99 per diluted share, for the
respective periods. This compares to net earnings of $499 million, or $1.12 per diluted share, for
the third quarter of 2009 and a net loss of $3.1 billion, or $7.09 per diluted share for the first
nine months of 2009. Our financial results for the third quarter and first nine months of 2010
include after-tax gains of $1.5 billion and $1.8 billion, respectively, related to International
offshore divestitures. Our financial results for the first nine months of 2009 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.
Key measures of our financial performance for the third quarter and first nine months of 2010
compared to 2009 are summarized below:
|
|
|
Production decreased 3% and 4% in the third quarter and first nine months of 2010,
respectively. Excluding the effects of property divestitures, North America Onshore
production climbed 4% and declined 1% for the respective third quarter and nine month
comparisons. |
|
|
|
|
The combined realized price without hedges for oil, gas and NGLs increased 17% and 33% in
the third quarter and first nine months of 2010, respectively. |
|
|
|
|
Oil, gas and NGL derivatives generated net gains of $209 million and $874 million in the
third quarter and first nine months of 2010, respectively, and net gains of $23 million and
$190 million in the third quarter and first nine months of 2009. Included in these amounts
were cash receipts of $232 million and $580 million for the third quarter and first nine
months of 2010, respectively, and cash receipts of $127 million and $359 million in the
third quarter and first nine months of 2009, respectively. |
|
|
|
|
Marketing and midstream operating profit increased 20% to $125 million and 1% to $383
million in the third quarter and first nine months of 2010, respectively. |
|
|
|
|
Per unit operating costs increased 3% to $7.35 per Boe and 4% to $7.44 per Boe in the
third quarter and first nine months of 2010, respectively. |
|
|
|
|
Operating cash flow increased 29% to $4.2 billion in the first nine months of 2010. |
|
|
|
|
Including a $500 million acquisition of a 50 percent interest in the Pike oil
sands, cash spent on capital expenditures was approximately $4.8 billion in the first nine
months of 2010. |
Throughout 2010, we have moved closer to completion of our offshore divestiture program
announced in November 2009. We have completed our exit from the Gulf of Mexico and have divested
our assets in Azerbaijan and China. Additionally, we have entered into an agreement to sell our
assets in Brazil for $3.2 billion. This transaction continues to progress through the approval
process of the Brazilian government and is on track to close around the end of 2010. The
divestiture process is ongoing for our exploration assets in Angola.
During the first nine months of 2010, our divestitures generated total after-tax proceeds of
$5.6 billion. In accordance with full cost accounting rules, we did not recognize a gain on the
Gulf of Mexico divestitures. The Azerbaijan and China divestitures generated gains of $1.5 billion
($1.5 billion after-tax) and $0.3 billion ($0.2 billion after-tax), respectively.
Once all divestiture assets are sold, we estimate the total pre-tax proceeds will approximate
$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 are using the divestiture proceeds to
invest in North America Onshore exploration and development opportunities, repurchase our common
shares and reduce outstanding debt.
26
In conjunction with certain offshore divestitures in the second quarter of 2010, we formed a
heavy oil joint venture to operate and develop the Pike oil sands leases in Alberta, Canada. As a
result, we acquired a 50 percent interest in the Pike oil sands leases for $500 million. We will
also fund $155 million of Canadian dollar capital costs on behalf of our joint-venture partner. The
majority of these costs are expected to be paid during 2011 and 2012.
Furthermore, in connection with the completed divestitures, we have substantially reduced our
deepwater drilling rig commitments. We no longer have lease commitments for the two deepwater
drilling rigs that were being used in the Gulf of Mexico. The third deepwater drilling rig is being
used in our Brazil operations and will be assumed by the buyer when that divestiture transaction
closes.
In May 2010, we announced a share repurchase program that authorizes the repurchase of up to
$3.5 billion of our common shares. Through September, we had repurchased 14.7 million shares for
$936 million, or $63.61 per share.
Additionally, we repaid all our outstanding commercial paper and redeemed our $350 million
7.25% senior notes prior to their scheduled maturity with proceeds from the U.S. Offshore
divestitures.
Finally, our performance and divestitures to date enabled us to end the third quarter of 2010
with a robust level of liquidity. As of September 30, 2010, we held $4.0 billion in cash and cash
equivalents and had $2.6 billion of available credit under our credit lines. This liquidity will
allow us to continue repurchasing common shares and investing in the opportunities that exist
across our North America Onshore portfolio of properties.
Third-Quarter Operating Highlights
We drilled 407 wells in the third quarter of 2010 with an overall success rate of 99 percent.
We achieved several notable operational accomplishments in the third-quarter:
|
|
|
Our oil and natural gas liquids production totaled 193 thousand barrels per day in the
third quarter of 2010. This represents an 11% increase in liquids production compared to the
third quarter of 2009. |
|
|
|
|
In the Permian Basin, increased oil and liquids-rich activity drove production 18% higher
than the year-ago quarter to 44,000 barrels per day. We are currently running 17 operated
rigs and have assembled nearly 1 million net acres of leasehold targeting the Avalon Shale,
Bone Spring, Wolfberry and other conventional formations. |
|
|
|
|
In Canada, net production from our Jackfish oil sands project averaged 21,300 barrels per
day in the third quarter. Jackfish was taken offline for scheduled plant maintenance during
the last three weeks of the third quarter and resumed operations on September 30, 2010. |
|
|
|
|
Construction of our second Jackfish oil sands project is now approximately 90% complete.
We plan to commence steam injection at Jackfish 2 in the second quarter of 2011, with first
production expected by the end of next year. |
|
|
|
|
We sanctioned our third Jackfish development project and filed a regulatory application
in the third quarter. We could begin facilities construction at Jackfish 3 by the end of
2011, with plant start-up targeted for 2015. |
|
|
|
|
Production from our Cana-Woodford Shale play in western Oklahoma averaged a record 117
million cubic feet of gas equivalent per day during the quarter. This represents an increase
in production of 122% over the year-ago quarter. We expect to commence operations from our
Cana gas processing plant by the end of 2010. |
|
|
|
|
In the Granite Wash in the Texas panhandle, we drilled three significant horizontal wells
in the third quarter. Initial production from these wells averaged 4,290 barrels of
oil-equivalent per day, including 605 barrels of oil and 1,450 barrels of natural gas
liquids per day. We have an average working interest of 65% in these wells. |
|
|
|
|
We increased our net production from the Barnett Shale field in north Texas to an
all-time high of 1.2 billion cubic feet of natural gas equivalent per day in the third
quarter, including 40,100 barrels per day of liquids production. This represents an 8%
increase in production compared to the third quarter of 2009. |
27
Results of Operations
Revenues
Our oil, gas and NGL production volumes are shown in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(2) |
|
|
2010 |
|
|
2009 |
|
|
Change(2) |
|
Oil (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
4 |
|
|
|
2 |
|
|
|
+27 |
% |
|
|
10 |
|
|
|
8 |
|
|
|
+13 |
% |
Canada |
|
|
6 |
|
|
|
6 |
|
|
|
+4 |
% |
|
|
19 |
|
|
|
19 |
|
|
|
+2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
10 |
|
|
|
8 |
|
|
|
+11 |
% |
|
|
29 |
|
|
|
27 |
|
|
|
+6 |
% |
U.S. Offshore |
|
|
|
|
|
|
2 |
|
|
|
-100 |
% |
|
|
2 |
|
|
|
4 |
|
|
|
-50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
10 |
|
|
|
10 |
|
|
|
-5 |
% |
|
|
31 |
|
|
|
31 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (Bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
179 |
|
|
|
172 |
|
|
|
+4 |
% |
|
|
518 |
|
|
|
536 |
|
|
|
-3 |
% |
Canada |
|
|
53 |
|
|
|
58 |
|
|
|
-9 |
% |
|
|
161 |
|
|
|
171 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
232 |
|
|
|
230 |
|
|
|
+1 |
% |
|
|
679 |
|
|
|
707 |
|
|
|
-4 |
% |
U.S. Offshore |
|
|
|
|
|
|
12 |
|
|
|
-100 |
% |
|
|
17 |
|
|
|
34 |
|
|
|
-50 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
232 |
|
|
|
242 |
|
|
|
-4 |
% |
|
|
696 |
|
|
|
741 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
7 |
|
|
|
6 |
|
|
|
+12 |
% |
|
|
21 |
|
|
|
19 |
|
|
|
+9 |
% |
Canada |
|
|
1 |
|
|
|
1 |
|
|
|
-3 |
% |
|
|
3 |
|
|
|
3 |
|
|
|
-5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
8 |
|
|
|
7 |
|
|
|
+10 |
% |
|
|
24 |
|
|
|
22 |
|
|
|
+7 |
% |
U.S. Offshore |
|
|
|
|
|
|
1 |
|
|
|
-100 |
% |
|
|
|
|
|
|
1 |
|
|
|
-38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
8 |
|
|
|
8 |
|
|
|
+8 |
% |
|
|
24 |
|
|
|
23 |
|
|
|
+6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (MMBoe) (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
41 |
|
|
|
38 |
|
|
|
+7 |
% |
|
|
117 |
|
|
|
117 |
|
|
|
+0 |
% |
Canada |
|
|
16 |
|
|
|
16 |
|
|
|
-4 |
% |
|
|
49 |
|
|
|
50 |
|
|
|
-3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
57 |
|
|
|
54 |
|
|
|
+4 |
% |
|
|
166 |
|
|
|
167 |
|
|
|
-1 |
% |
U.S. Offshore |
|
|
|
|
|
|
4 |
|
|
|
-100 |
% |
|
|
5 |
|
|
|
10 |
|
|
|
-49 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
57 |
|
|
|
58 |
|
|
|
-3 |
% |
|
|
171 |
|
|
|
177 |
|
|
|
-4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
The following table presents the prices we realized on our production volumes. These prices
exclude any effects due to our oil, gas and NGL derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
2010 |
|
|
2009 |
|
|
Change |
|
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
71.47 |
|
|
$ |
64.48 |
|
|
|
+11 |
% |
|
$ |
73.56 |
|
|
$ |
51.04 |
|
|
|
+44 |
% |
Canada |
|
$ |
56.89 |
|
|
$ |
55.10 |
|
|
|
+3 |
% |
|
$ |
57.90 |
|
|
$ |
43.42 |
|
|
|
+33 |
% |
North America Onshore |
|
$ |
62.31 |
|
|
$ |
58.15 |
|
|
|
+7 |
% |
|
$ |
63.22 |
|
|
$ |
45.83 |
|
|
|
+38 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
65.99 |
|
|
|
N/M |
|
|
$ |
77.81 |
|
|
$ |
56.19 |
|
|
|
+38 |
% |
Total |
|
$ |
62.31 |
|
|
$ |
59.32 |
|
|
|
+5 |
% |
|
$ |
64.12 |
|
|
$ |
47.09 |
|
|
|
+36 |
% |
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
3.65 |
|
|
$ |
2.77 |
|
|
|
+32 |
% |
|
$ |
3.91 |
|
|
$ |
2.99 |
|
|
|
+31 |
% |
Canada |
|
$ |
3.72 |
|
|
$ |
2.91 |
|
|
|
+28 |
% |
|
$ |
4.24 |
|
|
$ |
3.51 |
|
|
|
+21 |
% |
North America Onshore |
|
$ |
3.67 |
|
|
$ |
2.81 |
|
|
|
+31 |
% |
|
$ |
3.99 |
|
|
$ |
3.11 |
|
|
|
+28 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
3.49 |
|
|
|
N/M |
|
|
$ |
5.12 |
|
|
$ |
4.11 |
|
|
|
+25 |
% |
Total |
|
$ |
3.67 |
|
|
$ |
2.84 |
|
|
|
+29 |
% |
|
$ |
4.02 |
|
|
$ |
3.16 |
|
|
|
+27 |
% |
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change |
|
|
2010 |
|
|
2009 |
|
|
Change |
|
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
27.21 |
|
|
$ |
24.49 |
|
|
|
+11 |
% |
|
$ |
29.92 |
|
|
$ |
20.98 |
|
|
|
+43 |
% |
Canada |
|
$ |
43.89 |
|
|
$ |
33.81 |
|
|
|
+30 |
% |
|
$ |
46.34 |
|
|
$ |
30.20 |
|
|
|
+53 |
% |
North America Onshore |
|
$ |
29.01 |
|
|
$ |
25.63 |
|
|
|
+13 |
% |
|
$ |
31.81 |
|
|
$ |
22.18 |
|
|
|
+43 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
28.34 |
|
|
|
N/M |
|
|
$ |
38.22 |
|
|
$ |
23.51 |
|
|
|
+63 |
% |
Total |
|
$ |
29.01 |
|
|
$ |
25.67 |
|
|
|
+13 |
% |
|
$ |
31.90 |
|
|
$ |
22.21 |
|
|
|
+44 |
% |
Combined (per Boe) (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
27.18 |
|
|
$ |
21.48 |
|
|
|
+27 |
% |
|
$ |
28.83 |
|
|
$ |
20.86 |
|
|
|
+38 |
% |
Canada |
|
$ |
36.62 |
|
|
$ |
31.62 |
|
|
|
+16 |
% |
|
$ |
39.33 |
|
|
$ |
29.94 |
|
|
|
+31 |
% |
North America Onshore |
|
$ |
29.82 |
|
|
$ |
24.54 |
|
|
|
+22 |
% |
|
$ |
31.92 |
|
|
$ |
23.58 |
|
|
|
+35 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
39.67 |
|
|
|
N/M |
|
|
$ |
49.06 |
|
|
$ |
36.64 |
|
|
|
+34 |
% |
Total |
|
$ |
29.82 |
|
|
$ |
25.50 |
|
|
|
+17 |
% |
|
$ |
32.42 |
|
|
$ |
24.31 |
|
|
|
+33 |
% |
|
|
|
(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 September 30, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
2009 sales |
|
$ |
597 |
|
|
$ |
689 |
|
|
$ |
195 |
|
|
$ |
1,481 |
|
Changes due to volumes |
|
|
(33 |
) |
|
|
(29 |
) |
|
|
16 |
|
|
|
(46 |
) |
Changes due to prices |
|
|
29 |
|
|
|
191 |
|
|
|
28 |
|
|
|
248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 sales |
|
$ |
593 |
|
|
$ |
851 |
|
|
$ |
239 |
|
|
$ |
1,683 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The volume and price changes in the tables above caused the following changes to our oil, gas
and NGL sales between the nine months ended September 30, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
2009 sales |
|
$ |
1,465 |
|
|
$ |
2,340 |
|
|
$ |
501 |
|
|
$ |
4,306 |
|
Changes due to volumes |
|
|
(14 |
) |
|
|
(141 |
) |
|
|
29 |
|
|
|
(126 |
) |
Changes due to prices |
|
|
525 |
|
|
|
599 |
|
|
|
231 |
|
|
|
1,355 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 sales |
|
$ |
1,976 |
|
|
$ |
2,798 |
|
|
$ |
761 |
|
|
$ |
5,535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales increased $29 million in the third quarter of 2010 as a result of a 5% 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. This was partially offset by an increase in our price differential based upon the NYMEX
index price. The higher differential resulted primarily from the increase in our heavy oil
production and the widening of the associated differential related to our Canadian operations.
Oil sales decreased $33 million in the third quarter of 2010 due to a five percent decrease in
production. The decrease was primarily due to the divestiture of our U.S. Offshore properties in
the second quarter of 2010 partially offset by a 11% increase in our North America Onshore
production. The increased North America Onshore production resulted primarily from continued
development of our Permian Basin properties in Texas and our Jackfish operations in Canada.
Oil sales increased $525 million in the first nine months of 2010 as a result of a 36%
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.
29
Oil sales decreased $14 million in the first nine months of 2010 due to a one percent decrease
in production. The decrease was comprised of the net effects of a 50% decrease in our U.S. Offshore
production and a 6% increase in our North America Onshore production. The decrease in our U.S.
Offshore production was primarily due to the divestiture of such properties in the second quarter
of 2010. The increased North America Onshore production resulted primarily from continued
development of our Permian Basin properties in Texas and our Jackfish operations in Canada.
Gas Sales
Gas sales increased $191 million during the third quarter 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.
A 4% decrease in production during the third quarter of 2010 caused gas sales to decrease by
$29 million. The decrease was primarily due to the divestiture of our U.S. Offshore properties in
the second quarter of 2010 partially offset by a 1% increase in our North America Onshore
production. The increased North America Onshore production resulted primarily from continued
development activities in the Barnett and Cana Shales, partially offset by natural production
declines in our other operating areas.
Gas sales increased $599 million during the first nine months of 2010 as a result of a 27%
increase in our realized price without hedges. This increase is largely due to increases in the
North American regional index prices upon which our gas sales are based.
A 6% decrease in production during the first nine months of 2010 caused gas sales to decrease
by $141 million. The decrease in production was primarily due to reduced drilling during most of
2009 for our North America Onshore properties. As a result of reduced drilling activities during
the second half of 2009 in response to lower gas prices, natural declines of existing wells
outpaced production gains from new drilling. Also, the divestiture of our U.S. Offshore properties
in the second quarter of 2010 contributed to the decrease.
NGL Sales
NGL sales increased $28 million during the third quarter of 2010 as a result of a 13% increase
in our realized price without hedges. The increase was largely due to an increase in the Mont
Belvieu, Texas index price over the same time period. NGL sales increased $16 million in the third
quarter of 2010 due to an eight percent increase in production. The increase in production is
primarily due to increased drilling in North America Onshore areas that have liquids rich gas.
NGL sales increased $231 million during the first nine months of 2010 as a result of a 44%
increase in our realized price without hedges. The increase was largely due to an increase in the
Mont Belvieu, Texas index price over the same time period. NGL sales increased $29 million in the
first nine months of 2010 due to a six percent increase in production. The increase in production
is primarily due to increased drilling in North America Onshore areas that have liquids rich gas.
Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL
hedges. The first table presents the cash settlements and unrealized gains and losses 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.
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash settlements receipts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
206 |
|
|
$ |
9 |
|
|
$ |
543 |
|
|
$ |
9 |
|
Gas price collars |
|
|
17 |
|
|
|
118 |
|
|
|
30 |
|
|
|
350 |
|
Gas basis swaps |
|
|
9 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
232 |
|
|
|
127 |
|
|
|
580 |
|
|
|
359 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
145 |
|
|
|
(7 |
) |
|
|
303 |
|
|
|
(7 |
) |
Gas price collars |
|
|
12 |
|
|
|
(104 |
) |
|
|
31 |
|
|
|
(169 |
) |
Gas basis swaps |
|
|
(14 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
Gas call options |
|
|
(42 |
) |
|
|
|
|
|
|
(42 |
) |
|
|
|
|
Oil price collars |
|
|
(57 |
) |
|
|
7 |
|
|
|
71 |
|
|
|
7 |
|
Oil call options |
|
|
(68 |
) |
|
|
|
|
|
|
(68 |
) |
|
|
|
|
NGL basis swaps |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) on fair value changes |
|
|
(23 |
) |
|
|
(104 |
) |
|
|
294 |
|
|
|
(169 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL derivatives |
|
$ |
209 |
|
|
$ |
23 |
|
|
$ |
874 |
|
|
$ |
190 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2010 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
62.31 |
|
|
$ |
3.67 |
|
|
$ |
29.01 |
|
|
$ |
29.82 |
|
Cash settlements of hedges |
|
|
|
|
|
|
1.00 |
|
|
|
|
|
|
|
4.14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
62.31 |
|
|
$ |
4.67 |
|
|
$ |
29.01 |
|
|
$ |
33.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2009 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
59.32 |
|
|
$ |
2.84 |
|
|
$ |
25.67 |
|
|
$ |
25.50 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.52 |
|
|
|
|
|
|
|
2.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
59.32 |
|
|
$ |
3.36 |
|
|
$ |
25.67 |
|
|
$ |
27.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2010 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
64.12 |
|
|
$ |
4.02 |
|
|
$ |
31.90 |
|
|
$ |
32.42 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.83 |
|
|
|
|
|
|
|
3.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
64.12 |
|
|
$ |
4.85 |
|
|
$ |
31.90 |
|
|
$ |
35.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2009 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
47.09 |
|
|
$ |
3.16 |
|
|
$ |
22.21 |
|
|
$ |
24.31 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.48 |
|
|
|
|
|
|
|
2.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
47.09 |
|
|
$ |
3.64 |
|
|
$ |
22.21 |
|
|
$ |
26.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In 2010, our oil, gas and NGL derivatives included gas price swaps, oil and gas costless price
collars, gas and NGL basis swaps, and oil and gas call options. In 2009, our oil and gas
derivatives included gas price swaps and oil and gas costless 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. For the basis swaps, we receive a fixed
differential between two index prices and pay a variable differential on the same two index prices
to the contract counterparty. The oil and gas call options give the counterparty the right to place
us into an oil or gas price swap at a predetermined fixed price. Cash settlements as presented in
the tables above represent net realized gains related to our price swaps, price collars and basis
swaps.
31
During the third quarter and first nine months of 2010, we received $232 million, or $1.00 per
Mcf, and $580 million, or $0.83 per Mcf, respectively, from counterparties to settle our gas
derivatives. During the third quarter and first nine months of 2009, we received $127 million, or
$0.52 per Mcf, and $359 million, or $0.48 per Mcf, respectively, from counterparties to settle our
gas derivatives. We had no settlements on oil or NGL derivatives in any of these periods.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes
in the fair values of our oil, gas and NGL derivatives in each reporting period. We estimate the
fair values of our oil, gas and NGL derivatives 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 September 30, 2010, a 10% increase in these forward curves would have decreased the
fair value of our gas derivatives by approximately $163 million. A 10% increase in the forward
curves associated with our oil derivatives would have decreased the fair value of our oil
derivatives by approximately $95 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.
Finally, the amount of volumes subject to oil and gas derivatives is not a variable in our cash
flow calculations but does impact the total derivative values.
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 fourteen 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 September 30, 2010, the credit
ratings of all our counterparties were investment grade.
Including the cash settlements discussed above, the net gains from our oil, gas and NGL
derivatives were $209 million and $874 million during the third quarter and first nine months of
2010, respectively. Including the cash settlements discussed above, the net gains from our oil, gas
and NGL derivatives were $23 million and $190 million during the third quarter and first nine
months of 2009, respectively. In addition to the impact of cash settlements, these net gains were
impacted by new positions and settlements that occurred during each period, as well as the
relationships between contract prices and the associated forward curves. A summary of our
outstanding oil, gas and NGL derivative positions as of the end of the third quarter of 2010 is
included in Item 3. Quantitative and Qualitative Disclosures About Market Risk of this report.
Marketing and Midstream Revenues and Operating Costs and Expenses
The details of the changes in marketing and midstream revenues, operating costs and expenses
and the resulting operating profit are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
|
|
|
|
|
|
|
|
|
($ in millions) |
|
|
|
|
|
|
|
|
|
Marketing and midstream: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
461 |
|
|
$ |
344 |
|
|
|
+34 |
% |
|
$ |
1,396 |
|
|
$ |
1,074 |
|
|
|
+30 |
% |
Operating costs and expenses |
|
|
336 |
|
|
|
241 |
|
|
|
+40 |
% |
|
|
1,013 |
|
|
|
695 |
|
|
|
+46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
125 |
|
|
$ |
103 |
|
|
|
+20 |
% |
|
$ |
383 |
|
|
$ |
379 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 third quarter of 2010, marketing and midstream revenues increased $117 million and
operating costs and expenses increased $95 million, causing operating profit to increase $22
million. Revenues, expenses and operating profit increased primarily due to higher commodity prices
and natural gas and NGL production.
During the first nine months of 2010, marketing and midstream revenues increased $322 million
and operating costs and expenses increased $318 million, causing operating profit to increase $4
million. Revenues, expenses and operating profit
32
increased primarily due to higher commodity prices and NGL production, partially offset by the
effects of lower gas pipeline throughput and lower gas marketing profits.
Lease Operating Expenses (LOE)
The details of the changes in LOE are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
Lease operating expenses
($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
208 |
|
|
$ |
198 |
|
|
|
+5 |
% |
|
$ |
615 |
|
|
$ |
639 |
|
|
|
-4 |
% |
Canada |
|
|
207 |
|
|
|
172 |
|
|
|
+21 |
% |
|
|
596 |
|
|
|
500 |
|
|
|
+19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
415 |
|
|
|
370 |
|
|
|
+12 |
% |
|
|
1,211 |
|
|
|
1,139 |
|
|
|
+6 |
% |
U.S. Offshore |
|
|
|
|
|
|
46 |
|
|
|
-100 |
% |
|
|
60 |
|
|
|
127 |
|
|
|
-52 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
415 |
|
|
$ |
416 |
|
|
|
-0 |
% |
|
$ |
1,271 |
|
|
$ |
1,266 |
|
|
|
+0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
5.11 |
|
|
$ |
5.22 |
|
|
|
-2 |
% |
|
$ |
5.25 |
|
|
$ |
5.45 |
|
|
|
-4 |
% |
Canada |
|
$ |
13.14 |
|
|
$ |
10.44 |
|
|
|
+26 |
% |
|
$ |
12.23 |
|
|
$ |
9.98 |
|
|
|
+23 |
% |
North America Onshore |
|
$ |
7.35 |
|
|
$ |
6.80 |
|
|
|
+8 |
% |
|
$ |
7.30 |
|
|
$ |
6.81 |
|
|
|
+7 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
12.48 |
|
|
|
N/M |
|
|
$ |
12.00 |
|
|
$ |
12.83 |
|
|
|
-7 |
% |
Total |
|
$ |
7.35 |
|
|
$ |
7.16 |
|
|
|
+3 |
% |
|
$ |
7.44 |
|
|
$ |
7.14 |
|
|
|
+4 |
% |
|
|
|
(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 $1 million in the third quarter of 2010, which included a $46 million decrease
related to our U.S. Offshore operations and a $45 million increase related to our North America
Onshore operations. Our U.S. Offshore LOE decreased as a result of the divestiture of such
properties in the second quarter of 2010. Our North America Onshore LOE increased $14 million as a
result of our 4% increase in production and $11 million due to changes in the exchange rate between
the U.S. and Canadian dollars. The remaining increase primarily relates to increased costs related
to our Jackfish operations in Canada. The higher Jackfish costs relate to maintenance performed
during the third quarter of 2010, as well as clean up and repair costs associated with a temporary,
uncontrolled steam release in July 2010. These factors were also the main contributors to the
changes in LOE per Boe.
LOE increased $5 million in the first nine months of 2010, which included a $72 million
increase related to our North America Onshore operations and a $67 million decrease related to our
U.S. Offshore operations. North America Onshore LOE increased $69 million due to changes in the
exchange rate between the U.S. and Canadian dollars. North America Onshore LOE also increased $14
million due to increased costs related to our Jackfish operation in Canada. A 1% decrease in North
America Onshore production caused LOE to decline $11 million. U.S. Offshore LOE decreased primarily
due to property divestitures in the second quarter of 2010. The increase due to exchange rates was
also the main contributor to the changes in North America Onshore and total LOE per Boe.
Taxes Other Than Income Taxes
The following table details the changes in our taxes other than income taxes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
|
|
|
|
|
|
|
|
|
($ in millions) |
|
|
|
|
|
|
|
|
|
Production |
|
$ |
51 |
|
|
$ |
35 |
|
|
|
+46 |
% |
|
$ |
156 |
|
|
$ |
95 |
|
|
|
+64 |
% |
Ad valorem |
|
|
42 |
|
|
|
45 |
|
|
|
-7 |
% |
|
|
128 |
|
|
|
148 |
|
|
|
-14 |
% |
Other |
|
|
2 |
|
|
|
1 |
|
|
|
+11 |
% |
|
|
4 |
|
|
|
6 |
|
|
|
-38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
95 |
|
|
$ |
81 |
|
|
|
+16 |
% |
|
$ |
288 |
|
|
$ |
249 |
|
|
|
+15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and not the rounded
figures included in this table. |
33
Production taxes increased $16 million and $61 million in the third quarter and first nine
months of 2010, respectively, primarily due to an increase in our U.S. Onshore revenues. Ad valorem
taxes decreased $3 million and $20 million respectively, primarily due to lower estimated assessed
values of our U.S. Onshore oil and gas property and equipment.
Depreciation, Depletion and Amortization of Oil and Gas Properties (DD&A)
The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties
are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
Total production volumes (MMBoe) |
|
|
57 |
|
|
|
58 |
|
|
|
-3 |
% |
|
|
171 |
|
|
|
177 |
|
|
|
-4 |
% |
DD&A rate ($ per Boe) |
|
$ |
7.04 |
|
|
$ |
7.30 |
|
|
|
-4 |
% |
|
$ |
7.32 |
|
|
$ |
7.98 |
|
|
|
-8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
397 |
|
|
$ |
424 |
|
|
|
-6 |
% |
|
$ |
1,249 |
|
|
$ |
1,414 |
|
|
|
-12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
and nine months ended September 30, 2010 and 2009.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
(In millions) |
|
2009 DD&A |
|
$ |
424 |
|
|
$ |
1,414 |
|
Change due to volumes |
|
|
(12 |
) |
|
|
(51 |
) |
Change due to rate |
|
|
(15 |
) |
|
|
(114 |
) |
|
|
|
|
|
|
|
2010 DD&A |
|
$ |
397 |
|
|
$ |
1,249 |
|
|
|
|
|
|
|
|
Oil and gas property-related DD&A decreased $15 million during the third quarter of 2010 due
to a 4% decrease in the DD&A rate. The rate decreased primarily due to our U.S. Offshore property
divestitures in 2010. This was partially offset by our drilling and development activities
subsequent to the end of the third quarter of 2009, which resulted in proved reserve additions at a
cost higher than the third quarter 2009 DD&A rate, causing the rate to increase. In addition,
changes in the exchange rate between the U.S. and Canadian dollars also increased our rate.
Oil and gas property-related DD&A decreased $114 million during the first nine months of 2010
due to a 8% decrease in the DD&A rate. The largest contributors to the rate decrease were our 2010
U.S. Offshore property divestitures and a reduction of the carrying value of our United States oil
and gas properties recognized in the first quarter of 2009. This reduction totaled $6.4 billion and
resulted from a full cost ceiling limitation. These decreases were partially offset by the effect
from drilling and development activities, as well as changes in the exchange rate between the U.S.
and Canadian dollars, which both caused the rate to increase.
General and Administrative Expenses (G&A)
The following schedule includes the components of G&A expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
2010 |
|
|
2009 |
|
|
Change(1) |
|
|
|
|
|
|
|
|
|
|
|
($ in millions) |
|
|
|
|
|
|
|
|
|
Gross G&A |
|
$ |
235 |
|
|
$ |
249 |
|
|
|
-6 |
% |
|
$ |
720 |
|
|
$ |
830 |
|
|
|
-13 |
% |
Capitalized G&A |
|
|
(75 |
) |
|
|
(80 |
) |
|
|
-6 |
% |
|
|
(236 |
) |
|
|
(261 |
) |
|
|
-9 |
% |
Reimbursed G&A |
|
|
(29 |
) |
|
|
(33 |
) |
|
|
-16 |
% |
|
|
(85 |
) |
|
|
(97 |
) |
|
|
-13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
131 |
|
|
$ |
136 |
|
|
|
-3 |
% |
|
$ |
399 |
|
|
$ |
472 |
|
|
|
-15 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
34
Gross G&A and capitalized G&A decreased $14 million and $5 million, respectively, in the third
quarter of 2010 compared to the same period in 2009. The largest contributor to these decreases was
lower employee compensation and benefits resulting primarily from our 2010 offshore divestitures.
These decreases were partially offset by the effects of changes in the exchange rate between the
U.S. and Canadian dollars.
Gross G&A and capitalized G&A decreased $110 million and $25 million, respectively, in the
first nine months of 2010 compared to the same period in 2009. The largest contributor to the
decrease was lower severance costs associated with certain Gulf of Mexico employees that were
impacted by the integration of our Gulf of Mexico and International operations into one offshore
unit in the second quarter of 2009. In addition, gross G&A and capitalized G&A decreased due to
lower employee compensation and benefits resulting from our 2010 offshore divestitures, as well as
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
dollars.
Restructuring Costs
The following schedule includes the components of restructuring costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash severance |
|
$ |
(13 |
) |
|
$ |
|
|
|
$ |
(18 |
) |
|
$ |
|
|
Share-based awards |
|
|
(5 |
) |
|
|
|
|
|
|
(9 |
) |
|
|
|
|
Lease obligations |
|
|
70 |
|
|
|
|
|
|
|
70 |
|
|
|
|
|
Asset impairments |
|
|
11 |
|
|
|
|
|
|
|
11 |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
63 |
|
|
$ |
|
|
|
$ |
55 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee Severance
In the fourth quarter of 2009, we recognized $153 million of estimated employee severance
costs associated with the planned divestitures of our 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 included amounts related to cash severance costs and
accelerated vesting of share-based grants. Of the $153 million total, $105 million related to our
U.S. Offshore operations and the remainder related to our International discontinued operations.
We had divested all our U.S. Offshore assets by the end of the second quarter of 2010 and a
significant part of our International assets by the end of the third quarter of 2010. As a result
of these divestitures and associated employee terminations, we decreased our estimate of employee
severance costs in the second and third quarters of 2010 by $14 million and $21 million,
respectively. As a result, we now estimate we will incur approximately $118 million of employee
severance costs. The lower estimate results primarily from more offshore employees than previously
estimated receiving comparable positions with the purchaser of the properties or in our U.S.
Onshore operations. Of the $118 million total, $78 million relates to our U.S. Offshore operations
and the remainder relates to our International discontinued operations. Of the $14 million and $21
million reductions recognized during in the second and third quarters of 2010, $9 million and $18
million, respectively, relate to our U.S. Offshore operations and the remainders relate to our
International discontinued operations.
Lease Obligations
As a result of the divestitures discussed above, we ceased using certain office space that was
subject to non-cancellable operating lease arrangements. Consequently, in the third quarter of
2010, we recognized $70 million of restructuring costs that represent the present value of our
future obligations under the leases, net of anticipated sublease income. Our estimate of lease
obligations was based upon certain key estimates that could change over the term of the leases.
These estimates include the estimated sublease income that we may receive over the term of the
leases, as well as the amount of variable operating costs that we will be required to pay under the
leases.
35
Asset Impairments
In the third quarter of 2010, we recognized $11 million of asset impairment charges for
leasehold improvements and furniture associated with the office space we ceased using.
Interest Expense
The following schedule includes the components of interest expense.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Interest based on debt outstanding |
|
$ |
98 |
|
|
$ |
112 |
|
|
$ |
307 |
|
|
$ |
330 |
|
Capitalized interest |
|
|
(20 |
) |
|
|
(22 |
) |
|
|
(55 |
) |
|
|
(71 |
) |
Early retirement of debt |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
|
|
Other |
|
|
5 |
|
|
|
|
|
|
|
9 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
83 |
|
|
$ |
90 |
|
|
$ |
280 |
|
|
$ |
263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding decreased during the third quarter and first nine months of
2010 primarily due to the retirement of $177 million of 10.125% notes upon their maturity in the
fourth quarter of 2009 and the early redemption of our 7.25% senior notes as discussed below.
Capitalized interest decreased during the third quarter and first nine months of 2010
primarily due to the divestitures of our U.S. Offshore properties during the first half of 2010,
which was partially offset by higher capitalized interest associated with our Canadian oil sands
development projects.
In the second quarter of 2010, we redeemed $350 million of 7.25% senior notes prior to their
scheduled maturity of October 1, 2011. The notes were redeemed for $384 million, which represented
100 percent of the principal amount, a make-whole premium of $28 million and $6 million of accrued
and unpaid interest. On the date of redemption, these notes also had an unamortized premium of $9
million. The $19 million presented in the table above represents the net of the $28 million
make-whole premium and $9 million amortization of the remaining premium.
Interest-Rate and Other Financial Instruments
The details of the changes in our interest-rate and other financial instruments, which
consisted entirely of interest rate swaps, are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
(Gains) losses from interest rate swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settlements |
|
$ |
(17 |
) |
|
$ |
(14 |
) |
|
$ |
(37 |
) |
|
$ |
(35 |
) |
Unrealized fair value changes |
|
|
72 |
|
|
|
9 |
|
|
|
158 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
55 |
|
|
$ |
(5 |
) |
|
$ |
121 |
|
|
$ |
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
During the third quarter and first nine months of 2010, we received cash settlements totaling
$17 million and $37 million, respectively, from counterparties to settle our interest rate swaps.
During the third quarter and first nine months of 2009, we received cash settlements totaling $14
million and $35 million, respectively.
In addition to recognizing cash settlements, we also recognize unrealized changes in the fair
values of our interest rate swaps each reporting period. 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 calculations 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
36
Rate provided by a third party. Based on the notional amount subject to the interest rate
swaps at September 30, 2010, a 10% increase in these forward curves would have increased the fair
value of our interest rate swaps by approximately $63 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 September 30, 2010.
Including the cash settlements discussed above, the net losses from our interest rate swaps
were $55 million and $121 million during the third quarter and first nine months of 2010,
respectively. Including the cash settlements discussed above, the net gains from our interest rate
swaps were $5 million and $20 million during the third quarter and first nine months of 2009,
respectively. In addition to the impact of cash settlements, these net gains and losses were
impacted by new positions and settlements that occurred during each period, as well as the
relationships between contract rates and the associated future interest rate yields. A summary of
our outstanding interest rate swap positions as of the end of the third quarter of 2010 is included
in Item 3. Quantitative and Qualitative Disclosures About Market Risk of this report.
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.
Other, net
The following schedule includes the components of other, net.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Interest and dividend income |
|
$ |
(4 |
) |
|
$ |
(2 |
) |
|
$ |
(9 |
) |
|
$ |
(3 |
) |
Deep water royalties |
|
|
|
|
|
|
(84 |
) |
|
|
|
|
|
|
(84 |
) |
Other |
|
|
(4 |
) |
|
|
(6 |
) |
|
|
(25 |
) |
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(8 |
) |
|
$ |
(92 |
) |
|
$ |
(34 |
) |
|
$ |
(61 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of
this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief
from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain
years by the Minerals Management Service (the MMS) have contained price thresholds, such that if
the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not
be granted for that year.
In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the
legality of including price thresholds in deep water leases. Additionally, in January 2009 a
federal appellate court upheld this district court ruling. This judgment was later appealed to the
United States Supreme Court, which, in October 2009, declined to review the appellate courts
ruling. The Supreme Courts decision ended the MMSs judicial course to enforce the price
thresholds.
Prior to September 30, 2009, we had $84 million accrued for potential royalties on various
deep water leases. Based upon the Supreme Courts decision, we reduced to zero the $84 million loss
contingency accrual in the third quarter of 2009.
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.
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Total income tax expense (benefit) (In millions) |
|
$ |
270 |
|
|
$ |
89 |
|
|
$ |
1,045 |
|
|
$ |
(2,082 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
|
|
(35 |
%) |
U.S. taxes on foreign earnings |
|
|
3 |
% |
|
|
|
|
|
|
2 |
% |
|
|
|
|
Prior year tax return filings |
|
|
|
|
|
|
(13 |
%) |
|
|
|
|
|
|
(1 |
%) |
State income taxes |
|
|
1 |
% |
|
|
1 |
% |
|
|
1 |
% |
|
|
(1 |
%) |
Taxation on Canadian operations |
|
|
(1 |
%) |
|
|
|
|
|
|
(1 |
%) |
|
|
|
|
Other |
|
|
1 |
% |
|
|
(4 |
%) |
|
|
(1 |
%) |
|
|
(2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax (benefit) rate |
|
|
39 |
% |
|
|
19 |
% |
|
|
36 |
% |
|
|
(39 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
In the second and third quarters of 2010, we recognized $52 million and $23 million,
respectively, of deferred income tax expense related to assumed repatriations of earnings from
certain of our foreign subsidiaries whose statutory tax rates are less than the U.S. statutory tax
rate.
In the third quarter of 2009, we recognized $59 million of income tax benefits in conjunction
with the initial or amended filings of our 2005, 2006, 2007 and 2008 income tax returns. These tax
benefits consist of deferred tax benefits of $50 million and current tax benefits of $9 million. Of
the $59 million, $41 million relates to taxation on foreign operations. The remaining $18 million
relates to taxation on U.S. federal and state operations.
Our 2010 Gulf of Mexico divestitures have taxable gains that increase our current income tax
expense by $858 million. However, the additional current income taxes are offset by a decrease in
deferred income tax expense, resulting in no impact to our total income tax expense.
Additionally, in conjunction with the filing of our 2009 income tax return in the third
quarter of 2010, we recognized a $220 million decrease to current income tax expense that was
offset by a like increase to deferred income tax expense. These amounts relate to a change in the
timing of certain deductions, which we decided to expense rather than capitalize for the 2009 tax
year. Such deductions created a net operating loss for the 2009 tax year that we are using to
reduce our 2010 current income taxes that would otherwise be due as a result of the taxable
divestiture gains mentioned above.
Earnings from Discontinued Operations
The following table presents the components of our earnings from discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
2010 |
|
|
2009 |
|
Total production (MMBoe) |
|
|
2 |
|
|
|
4 |
|
|
|
8 |
|
|
|
12 |
|
Combined price without hedges (per Boe) |
|
$ |
67.55 |
|
|
$ |
65.42 |
|
|
$ |
72.01 |
|
|
$ |
54.85 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
Operating revenues |
|
$ |
139 |
|
|
$ |
250 |
|
|
$ |
573 |
|
|
$ |
646 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
39 |
|
|
|
132 |
|
|
|
168 |
|
|
|
364 |
|
Reduction of carrying value of oil and gas properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
109 |
|
Gain on sale of oil and gas properties |
|
|
(1,535 |
) |
|
|
|
|
|
|
(1,843 |
) |
|
|
|
|
Other, net |
|
|
(75 |
) |
|
|
(3 |
) |
|
|
(72 |
) |
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
(1,571 |
) |
|
|
129 |
|
|
|
(1,747 |
) |
|
|
448 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before income taxes |
|
|
1,710 |
|
|
|
121 |
|
|
|
2,320 |
|
|
|
198 |
|
Income tax expense |
|
|
49 |
|
|
|
4 |
|
|
|
187 |
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
$ |
1,661 |
|
|
$ |
117 |
|
|
$ |
2,133 |
|
|
$ |
164 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings increased $1.5 billion in the third quarter of 2010 primarily as a result of the $1.5
billion gain ($1.5 billion after taxes) from the divestiture of our Azerbaijan operations.
38
Earnings increased $2.0 billion in the first nine months of 2010 primarily as a result of the
$1.5 billion gain ($1.5 billion after taxes) from the divestiture of our Azerbaijan operations and
the $308 million gain ($235 million after taxes) from the divestiture of our Panyu operations in
China. Also, earnings increased $109 million due to the 2009 reductions of carrying value 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.
Earnings in both the third quarter and first nine months of 2010 also decreased due to
production declines, resulting from the 2010 asset divestitures.
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
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
3,912 |
|
|
$ |
2,935 |
|
Divestitures of property and equipment |
|
|
4,131 |
|
|
|
23 |
|
Cash distributed from discontinued operations |
|
|
2,824 |
|
|
|
6 |
|
Commercial paper borrowings |
|
|
|
|
|
|
1,368 |
|
Debt issuance, net of commercial paper repayments |
|
|
|
|
|
|
182 |
|
Redemptions of long-term investments |
|
|
20 |
|
|
|
6 |
|
Stock option exercises |
|
|
18 |
|
|
|
19 |
|
Other |
|
|
7 |
|
|
|
6 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
10,912 |
|
|
|
4,545 |
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(4,793 |
) |
|
|
(3,807 |
) |
Commercial paper repayments |
|
|
(1,432 |
) |
|
|
|
|
Repurchases of common stock |
|
|
(929 |
) |
|
|
|
|
Debt repayments |
|
|
(350 |
) |
|
|
(1 |
) |
Dividends |
|
|
(211 |
) |
|
|
(213 |
) |
Other |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(7,728 |
) |
|
|
(4,021 |
) |
|
|
|
|
|
|
|
Increase from continuing operations |
|
|
3,184 |
|
|
|
524 |
|
Decrease from discontinued operations, including
distributions to continuing operations |
|
|
(202 |
) |
|
|
(25 |
) |
Effect of foreign exchange rates |
|
|
5 |
|
|
|
29 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
$ |
2,987 |
|
|
$ |
528 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
3,998 |
|
|
$ |
912 |
|
|
|
|
|
|
|
|
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 nine 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 nine months of 2010, our operating cash flow funded approximately 82% of our
cash payments for capital expenditures. However, our capital expenditures for the first nine months
of 2010 included $500 million that Devon paid to form a heavy oil joint venture and acquire a 50
percent interest in the Pike oil sands in Alberta, Canada. This acquisition was
39
completed in
connection with offshore divestitures discussed below. Excluding this $500 million acquisition, our
operating cash flow funded over 90% of our capital expenditures during the first nine months of
2010.
During the first nine months of 2009, our operating cash flow funded approximately 77% 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 senior credit facility 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 nine months of 2010, we completed the divestiture of our U.S. Offshore,
Azerbaijan and China properties, generating $6.6 billion in pre-tax proceeds net of closing
adjustments, or $5.6 billion after taxes. We have used proceeds from these divestitures to repay
all our commercial paper borrowings, retire $350 million of other debt that was to mature in
October 2011 and begin repurchasing our common shares. In addition, we began redeploying proceeds
into our North America Onshore properties, including the $500 million Pike oil sands acquisition
mentioned above.
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 Devons $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
$1.4 billion to fund capital expenditures in excess of our operating cash flow.
Capital Expenditures
Our capital expenditures are presented by geographic area and type in the following table. The
amounts in the table below reflect cash payments for capital expenditures, including cash paid for
capital expenditures incurred in prior quarters. Capital expenditures actually incurred during the
first nine months of 2010 and 2009 were approximately $5.0 billion and $3.3 billion, respectively.
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2010 |
|
|
2009 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
2,564 |
|
|
$ |
2,043 |
|
Canada |
|
|
1,438 |
|
|
|
747 |
|
|
|
|
|
|
|
|
North America Onshore |
|
|
4,002 |
|
|
|
2,790 |
|
U.S. Offshore |
|
|
365 |
|
|
|
704 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
4,367 |
|
|
|
3,494 |
|
Midstream |
|
|
176 |
|
|
|
230 |
|
Other |
|
|
250 |
|
|
|
83 |
|
|
|
|
|
|
|
|
Total continuing operations |
|
$ |
4,793 |
|
|
$ |
3,807 |
|
|
|
|
|
|
|
|
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 $4.4 billion and $3.5 billion in the first nine months of 2010 and 2009,
respectively. The increase in exploration and development capital spending in the first nine months
of 2010 was partially due to the $500 million Pike oil sands acquisition mentioned above.
Additionally, with rising oil and NGL prices and proceeds from our offshore divestiture program, we
are increasing drilling primarily to grow liquids production across our North America Onshore
portfolio of properties.
Capital expenditures for our midstream operations are primarily for the construction and
expansion of natural gas processing plants, natural gas gathering and pipeline systems and oil
pipelines. Our midstream capital expenditures in 2010 were largely impacted by reduced U.S. Onshore
dry gas drilling activities.
40
Capital expenditures related to corporate activities increased in 2010. This increase is
largely driven by the construction of our new headquarters in Oklahoma City.
Net Repayments of Debt
During the first nine months of 2010, we repaid $1.4 billion of commercial paper borrowings
and redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1,
2011, primarily with proceeds received from our U.S. Offshore divestitures.
Repurchases of Common Stock
During the second quarter of 2010, we began repurchasing shares under our $3.5 billion stock
repurchase program announced in May 2010. Including unsettled shares, we had repurchased 14.7
million common shares for $936 million, or $63.61 per share through September 2010.
Dividends
Our common stock dividends were $211 million and $213 million (quarterly rates of $0.16 per
share) in the first nine 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.
Operating Cash Flow
Our operating cash flow increased approximately 29% to $4.2 billion in the first nine 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, gas and NGLs produced. To mitigate some of the risk inherent in prices, we have utilized
various price collars related to a portion of our oil and gas production. We have also utilized
various price swap contracts and fixed-price physical delivery contracts related to a portion of
our future natural gas production. As of September 30, 2010, approximately 61% of our estimated
2010 gas production and 70% of our estimated oil production are subject to either price collars,
swaps or fixed-price contracts.
Looking beyond 2010, we have also entered into contracts to manage the price risk relative to
our 2011 and 2012 oil and gas production. A summary of these contracts as of the end of the third
quarter of 2010 is included in Item 3. Quantitative and Qualitative Disclosures About Market Risk
of this report.
Offshore Divestitures
During 2010, another major source of liquidity are proceeds generated from divestitures of our
offshore assets. In the first nine months of 2010, we completed our exit from the Gulf of Mexico
and divested our assets in Azerbaijan and China, generating total after-tax proceeds of $5.6
billion. Additionally, we have entered into an agreement to sell our assets in Brazil for $3.2
billion. The Brazil transaction continues to progress through the approval process of the Brazilian
government and is on track to close around the end of 2010. The divestiture process is ongoing for
our exploration assets in Angola.
Once all divestiture assets are sold, we estimate the total pre-tax proceeds will approximate
$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 are using the divestiture proceeds to
invest in North America Onshore exploration and development opportunities, repurchase our common
shares and reduce outstanding debt.
Furthermore, in connection with the completed divestitures, we have substantially reduced our
deepwater drilling rig commitments. We no longer have lease commitments for the two deepwater
drilling rigs that were being used in the Gulf of
41
Mexico. The third deepwater drilling rig is being
used in our Brazil operations and will be assumed by the buyer when that divestiture transaction
closes.
Credit Availability
In 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 September 30, 2010, we had $2.6 billion of available capacity under our syndicated,
unsecured Senior Credit Facility that can be used to supplement our operating cash flow and cash on
hand 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
September 30, 2010 (in millions).
|
|
|
|
|
April 7, 2012 maturity |
|
$ |
463 |
|
April 7, 2013 maturity |
|
|
2,187 |
|
|
|
|
|
Total Senior Credit Facility |
|
|
2,650 |
|
Less: |
|
|
|
|
Outstanding credit facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
|
|
Outstanding letters of credit |
|
|
37 |
|
|
|
|
|
Total available capacity |
|
$ |
2,613 |
|
|
|
|
|
As noted in the table above, we had no short-term borrowings as of September 30, 2010 or
during the third quarter of 2010. Our weighted average short-term borrowings for the first nine
months of 2010 were $0.3 billion.
The Senior Credit Facility contains only one material financial covenant. This covenant
requires us to maintain a ratio of total funded debt to total capitalization, as defined in the
credit agreement, of no more than 65%. The credit agreement defines total funded debt as funds
received through the issuance of debt securities such as debentures, bonds, notes payable, credit
facility borrowings and short-term commercial paper borrowings. In addition, total funded debt
includes all obligations with respect to payments received in consideration for oil, gas and NGL
production yet to be acquired or produced at the time of payment. Funded debt excludes our
outstanding letters of credit and trade payables. The credit agreement defines total capitalization
as the sum of funded debt and stockholders equity adjusted for noncash financial writedowns, such
as full cost ceiling impairments. As of September 30, 2010, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at September 30, 2010, as calculated pursuant to the
terms of the agreement, was 15.3%.
In 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 $0.9 billion that related to long-term lease
contracts for two deepwater drilling rigs being used in the Gulf of Mexico. As discussed above, we
no longer have lease commitments for these two rigs.
At the end of 2009, our commitments also included $0.5 billion that related to a long-term
lease contract for a deepwater drilling rig being used in Brazil. Our lease and remaining
commitments for this rig will be assumed by the buyer of our assets in Brazil when the associated
divestiture transaction closes.
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 the Gulf of Mexico and China leases were assumed by the purchasers
of the associated properties in the first nine months of 2010. Our Brazil lease will be assumed by
the buyer when the associated divestiture transaction closes.
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 May 2010. The program authorizes the repurchase of up to
$3.5 billion of our common shares and expires December 31, 2011.
42
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have commodity derivatives that pertain to production for the remainder of 2010, as well as
2011 and 2012. The key terms to our oil, gas and NGL derivatives as of September 30, 2010 are
presented in the following tables.
|
|
|
|
|
|
|
|
|
Gas Price Swaps |
|
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
Period |
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Fourth quarter 2010 |
|
|
1,265,000 |
|
|
$ |
6.16 |
|
Total year 2011 |
|
|
525,000 |
|
|
$ |
5.56 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
Fourth quarter 2010 |
|
|
355,000 |
|
|
$ |
4.50 - $5.50 |
|
|
$ |
4.85 |
|
|
$ |
5.40 - $7.10 |
|
|
$ |
6.12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
Differential to |
|
|
|
|
|
|
|
Volume |
|
|
Henry Hub |
|
Period |
|
Index |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Fourth quarter 2010 |
|
AECO |
|
|
150,000 |
|
|
$ |
0.33 |
|
Fourth quarter 2010 |
|
CIG |
|
|
70,000 |
|
|
$ |
0.37 |
|
Total year 2011 |
|
Panhandle Eastern Pipeline |
|
|
135,000 |
|
|
$ |
0.34 |
|
|
|
|
|
|
|
|
|
|
Gas Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
Period |
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Total year 2012 |
|
|
300,000 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
Fourth quarter 2010 |
|
|
79,000 |
|
|
$ |
65.00 - $70.00 |
|
|
$ |
67.47 |
|
|
$ |
90.35 - $103.30 |
|
|
$ |
96.48 |
|
Total year 2011 |
|
|
33,000 |
|
|
$ |
75.00 - $75.00 |
|
|
$ |
75.00 |
|
|
$ |
105.00 - $116.10 |
|
|
$ |
109.00 |
|
|
|
|
|
|
|
|
|
|
Oil Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
Period |
|
(Bbls /d) |
|
|
($/Bbl) |
|
Total year 2011 |
|
|
12,000 |
|
|
$ |
95.00 |
|
Total year 2012 |
|
|
12,000 |
|
|
$ |
95.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Basis Swaps |
|
|
|
|
|
|
|
Pay |
|
|
Receive |
|
|
|
Volume |
|
|
Natural Gasoline |
|
|
Oil |
|
Period |
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
Total year 2011 |
|
|
500 |
|
|
$ |
70.77 |
|
|
$ |
80.52 |
|
Total year 2012 |
|
|
500 |
|
|
$ |
71.82 |
|
|
$ |
81.92 |
|
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 September 30, 2010, a 10%
increase in the forward curves associated with our
43
gas price swaps and collars would have
decreased the fair value of such instruments by approximately $163 million. A 10% increase in the
forward curves associated with our oil collars would have decreased the fair value of such
instruments by approximately $95 million.
Interest Rate Risk
At September 30, 2010, we had debt outstanding of $5.6 billion with fixed rates averaging
7.2%.
The key terms of our interest rate derivatives as of September 30, 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) |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
950 |
|
|
|
3.92 |
% |
|
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 September 30, 2010, a 10% increase in these
forward curves would have increased the fair value of our interest rate swaps by approximately $63
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 September 30, 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.
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 September 30, 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 third
quarter of 2010 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
44
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.
Item 1A. Risk Factors
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
|
Maximum Dollar |
|
|
|
|
|
|
|
|
|
|
|
Shares Purchased as |
|
|
Value of Shares |
|
|
|
|
|
|
|
|
|
|
|
Part of Publicly |
|
|
that May Yet Be |
|
|
|
|
|
|
|
|
|
|
|
Announced |
|
|
Purchased Under the |
|
|
|
Total Number of |
|
|
Average Price Paid |
|
|
Plans or |
|
|
Plans or |
|
2010 Period |
|
Shares Purchased |
|
|
per Share |
|
|
Programs (1) |
|
|
Programs (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
July |
|
|
4,284,300 |
|
|
$ |
62.07 |
|
|
|
4,284,300 |
|
|
$ |
2,739 |
|
August |
|
|
1,442,100 |
|
|
$ |
61.30 |
|
|
|
1,442,100 |
|
|
$ |
2,651 |
|
September |
|
|
1,377,600 |
|
|
$ |
62.80 |
|
|
|
1,377,600 |
|
|
$ |
2,564 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
7,104,000 |
|
|
$ |
62.05 |
|
|
|
7,104,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In May 2010, our Board of Directors approved a $3.5 billion share repurchase
program. This program expires December 31, 2011. As of September 30, 2010, we have
repurchased 14.7 million common shares for $936 million, or $63.61 per share under this
program. |
Item 3. Defaults Upon Senior Securities
None.
Item 5. Other Information
None.
Item 6. Exhibits
(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 |
45
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: November 4, 2010 |
/s/ Danny J. Heatly
|
|
|
Danny J. Heatly |
|
|
Senior Vice President Accounting and
Chief Accounting Officer |
|
46
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 |
47