e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State of other jurisdiction of incorporation or organization)
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73-1567067
(I.R.S. Employer identification No.) |
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20 North Broadway, Oklahoma City, Oklahoma
(Address of principal executive offices)
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73102-8260
(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.
Large accelerated filer þ |
Accelerated filer o |
Non-accelerated filer o (Do not check if a smaller reporting company) |
Smaller reporting company o |
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 July 22, 2011, 416.5 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
For the Quarterly Period Ended June 30, 2011
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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Bcfe means billion cubic feet equivalent. |
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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 divested operations of Devon that encompassed 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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FASB means the United States Financial Accounting Standards Board. |
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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, 2010 reserve reports and other data in our possession or available from
third parties. In addition, forward-looking statements generally can be identified by the use of
forward-looking terminology such as may, will, expect, intend, project, estimate,
anticipate, believe, or continue or similar terminology. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can give no assurance
that such expectations will prove to have been correct. Important factors that could cause actual
results to differ materially from our expectations include, but are not limited to, our assumptions
about:
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energy markets, including the supply and demand for oil, gas, NGLs and other products or
services, as well as the prices of oil, gas, NGLs and other products or services, including
regional pricing differentials; |
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production levels, including Canadian production subject to government royalties, which
fluctuate with prices and 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 and changes in
environmental laws, regulation and liability; |
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terrorism; |
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occurrence of property acquisitions or divestitures; and |
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other factors disclosed in Devons 2010 Annual Report on Form 10-K under Item 1A. Risk
Factors, Item 2. Properties, 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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June 30, |
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December 31, |
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2011 |
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2010 |
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(Unaudited) |
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(In millions, except share data) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
3,351 |
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$ |
2,866 |
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Short-term investments |
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3,367 |
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145 |
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Accounts receivable |
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1,446 |
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1,202 |
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Current assets held for sale |
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36 |
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563 |
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Other current assets |
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711 |
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779 |
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Total current assets |
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8,911 |
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5,555 |
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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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59,423 |
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56,012 |
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Not subject to amortization |
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3,915 |
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3,434 |
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Total oil and gas |
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63,338 |
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59,446 |
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Other |
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4,732 |
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4,429 |
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Total property and equipment, at cost |
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68,070 |
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63,875 |
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Less accumulated depreciation, depletion and amortization |
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(45,643 |
) |
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(44,223 |
) |
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Property and equipment, net |
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22,427 |
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19,652 |
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Goodwill |
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6,176 |
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6,080 |
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Long-term assets held for sale |
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94 |
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859 |
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Other long-term assets |
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929 |
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781 |
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Total assets |
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$ |
38,537 |
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$ |
32,927 |
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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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$ |
1,365 |
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$ |
1,411 |
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Revenues and royalties due to others |
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669 |
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538 |
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Short-term debt |
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1,962 |
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1,811 |
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Current liabilities associated with assets held for sale |
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43 |
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305 |
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Other current liabilities |
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445 |
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518 |
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Total current liabilities |
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4,484 |
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4,583 |
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Long-term debt |
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5,968 |
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3,819 |
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Asset retirement obligations |
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1,499 |
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1,423 |
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Liabilities associated with assets held for sale |
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2 |
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26 |
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Other long-term liabilities |
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808 |
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1,067 |
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Deferred income taxes |
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4,348 |
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2,756 |
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Stockholders equity: |
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Common stock of $0.10 par value. Authorized 1.0 billion shares;
issued 418.3 million and 431.9 million shares in 2011 and 2010, respectively |
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42 |
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43 |
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Additional paid-in capital |
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4,489 |
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5,601 |
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Retained earnings |
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14,901 |
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11,882 |
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Accumulated other comprehensive earnings |
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2,021 |
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1,760 |
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Treasury stock, at cost. 0.3 million and 0.4 million shares in 2011 and 2010,
respectively |
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(25 |
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(33 |
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Total stockholders equity |
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21,428 |
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19,253 |
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Commitments and contingencies (Note 11) |
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Total liabilities and stockholders equity |
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$ |
38,537 |
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$ |
32,927 |
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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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Six Months Ended |
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June 30, |
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June 30, |
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2011 |
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2010 |
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2011 |
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2010 |
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(Unaudited) |
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(In millions, except |
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per share amounts) |
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Revenues: |
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Oil, gas and NGL sales |
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$ |
2,200 |
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$ |
1,782 |
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$ |
4,060 |
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$ |
3,852 |
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Oil, gas and NGL derivatives |
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416 |
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45 |
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248 |
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665 |
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Marketing and midstream revenues |
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604 |
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405 |
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1,059 |
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935 |
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Total revenues |
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3,220 |
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2,232 |
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5,367 |
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5,452 |
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Expenses and other, net: |
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Lease operating expenses |
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453 |
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442 |
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877 |
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856 |
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Taxes other than income taxes |
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120 |
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92 |
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228 |
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193 |
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Marketing and midstream operating costs and expenses |
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456 |
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280 |
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789 |
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677 |
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Depreciation, depletion and amortization of oil and gas properties |
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485 |
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426 |
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927 |
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852 |
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Depreciation and amortization of non-oil and gas properties |
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65 |
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63 |
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129 |
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126 |
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Accretion of asset retirement obligations |
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23 |
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24 |
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46 |
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50 |
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General and administrative expenses |
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135 |
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130 |
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265 |
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268 |
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Restructuring costs |
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6 |
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(8 |
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1 |
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(8 |
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Interest expense |
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85 |
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111 |
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166 |
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197 |
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Interest-rate and other financial instruments |
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25 |
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81 |
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8 |
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66 |
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Other, net |
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(11 |
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(22 |
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(27 |
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(26 |
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Total expenses and other, net |
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1,842 |
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1,619 |
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3,409 |
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3,251 |
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Earnings from continuing operations before income taxes |
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1,378 |
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613 |
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1,958 |
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2,201 |
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Income tax expense (benefit): |
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Current |
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36 |
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707 |
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(53 |
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1,006 |
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Deferred |
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1,158 |
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(446 |
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1,438 |
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(231 |
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Total income tax expense |
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1,194 |
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261 |
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1,385 |
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775 |
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Earnings from continuing operations |
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184 |
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352 |
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573 |
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1,426 |
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Discontinued operations: |
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Earnings from discontinued operations before income taxes |
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2,558 |
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473 |
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2,588 |
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610 |
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Discontinued operations income tax (benefit) expense |
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(1 |
) |
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119 |
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2 |
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138 |
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Earnings from discontinued operations |
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2,559 |
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|
354 |
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2,586 |
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472 |
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Net earnings |
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$ |
2,743 |
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$ |
706 |
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$ |
3,159 |
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$ |
1,898 |
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Basic net earnings per share: |
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Basic earnings from continuing operations per share |
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$ |
0.44 |
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$ |
0.79 |
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$ |
1.35 |
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$ |
3.20 |
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Basic earnings from discontinued operations per share |
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|
6.06 |
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|
0.80 |
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|
6.09 |
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|
1.06 |
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Basic net earnings per share |
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$ |
6.50 |
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$ |
1.59 |
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$ |
7.44 |
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$ |
4.26 |
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Diluted net earnings per share: |
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Diluted earnings from continuing operations per share |
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$ |
0.43 |
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$ |
0.79 |
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$ |
1.34 |
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$ |
3.19 |
|
Diluted earnings from discontinued operations per share |
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6.05 |
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0.79 |
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6.07 |
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1.05 |
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Diluted net earnings per share |
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$ |
6.48 |
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$ |
1.58 |
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$ |
7.41 |
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$ |
4.24 |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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|
2011 |
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|
2010 |
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|
2011 |
|
|
2010 |
|
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(Unaudited) |
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(In millions) |
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Net earnings |
|
$ |
2,743 |
|
|
$ |
706 |
|
|
$ |
3,159 |
|
|
$ |
1,898 |
|
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment |
|
|
67 |
|
|
|
(326 |
) |
|
|
262 |
|
|
|
(104 |
) |
Foreign currency translation income tax (expense) benefit |
|
|
(2 |
) |
|
|
17 |
|
|
|
(12 |
) |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation total |
|
|
65 |
|
|
|
(309 |
) |
|
|
250 |
|
|
|
(99 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial loss and prior service cost in earnings |
|
|
8 |
|
|
|
8 |
|
|
|
17 |
|
|
|
16 |
|
Pension and postretirement benefit plans income tax expense |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(6 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans total |
|
|
5 |
|
|
|
5 |
|
|
|
11 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive earnings (loss), net of tax |
|
|
70 |
|
|
|
(304 |
) |
|
|
261 |
|
|
|
(89 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive earnings |
|
$ |
2,813 |
|
|
$ |
402 |
|
|
$ |
3,420 |
|
|
$ |
1,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
Six Months Ended June 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2010 |
|
|
432 |
|
|
$ |
43 |
|
|
$ |
5,601 |
|
|
$ |
11,882 |
|
|
$ |
1,760 |
|
|
$ |
(33 |
) |
|
$ |
19,253 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,159 |
|
|
|
|
|
|
|
|
|
|
|
3,159 |
|
Other comprehensive earnings (loss), net
of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
261 |
|
|
|
|
|
|
|
261 |
|
Stock option exercises |
|
|
2 |
|
|
|
|
|
|
|
96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
96 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,285 |
) |
|
|
(1,285 |
) |
Common stock retired |
|
|
(16 |
) |
|
|
(1 |
) |
|
|
(1,292 |
) |
|
|
|
|
|
|
|
|
|
|
1,293 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(140 |
) |
|
|
|
|
|
|
|
|
|
|
(140 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
72 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
72 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2011 |
|
|
418 |
|
|
$ |
42 |
|
|
$ |
4,489 |
|
|
$ |
14,901 |
|
|
$ |
2,021 |
|
|
$ |
(25 |
) |
|
$ |
21,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009 |
|
|
447 |
|
|
$ |
45 |
|
|
$ |
6,527 |
|
|
$ |
7,613 |
|
|
$ |
1,385 |
|
|
$ |
|
|
|
$ |
15,570 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,898 |
|
|
|
|
|
|
|
|
|
|
|
1,898 |
|
Other comprehensive earnings (loss), net
of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(89 |
) |
|
|
|
|
|
|
(89 |
) |
Stock option exercises |
|
|
|
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(503 |
) |
|
|
(503 |
) |
Common stock retired |
|
|
(7 |
) |
|
|
(1 |
) |
|
|
(437 |
) |
|
|
|
|
|
|
|
|
|
|
438 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(142 |
) |
|
|
|
|
|
|
|
|
|
|
(142 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2010 |
|
|
440 |
|
|
$ |
44 |
|
|
$ |
6,186 |
|
|
$ |
9,369 |
|
|
$ |
1,296 |
|
|
$ |
(65 |
) |
|
$ |
16,830 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
3,159 |
|
|
$ |
1,898 |
|
Earnings from discontinued operations, net of tax |
|
|
(2,586 |
) |
|
|
(472 |
) |
Adjustments to reconcile earnings from continuing operations
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
1,056 |
|
|
|
978 |
|
Deferred income tax expense (benefit) |
|
|
1,438 |
|
|
|
(231 |
) |
Unrealized change in fair value of financial instruments |
|
|
(74 |
) |
|
|
(231 |
) |
Other noncash charges |
|
|
82 |
|
|
|
81 |
|
Net (increase) decrease in working capital |
|
|
(89 |
) |
|
|
581 |
|
Decrease in long-term other assets |
|
|
45 |
|
|
|
14 |
|
(Decrease) increase in long-term other liabilities |
|
|
(201 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
Cash from operating activities continuing operations |
|
|
2,830 |
|
|
|
2,619 |
|
Cash from operating activities discontinued operations |
|
|
(20 |
) |
|
|
273 |
|
|
|
|
|
|
|
|
Net cash from operating activities |
|
|
2,810 |
|
|
|
2,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(3,720 |
) |
|
|
(3,221 |
) |
Proceeds from property and equipment divestitures |
|
|
5 |
|
|
|
4,129 |
|
Purchases of short-term investments |
|
|
(4,520 |
) |
|
|
|
|
Redemptions of short-term investments |
|
|
1,298 |
|
|
|
|
|
Redemptions of long-term investments |
|
|
1 |
|
|
|
18 |
|
Other |
|
|
(33 |
) |
|
|
|
|
|
|
|
|
|
|
|
Cash from investing activities continuing operations |
|
|
(6,969 |
) |
|
|
926 |
|
Cash from investing activities discontinued operations |
|
|
3,170 |
|
|
|
429 |
|
|
|
|
|
|
|
|
Net cash from investing activities |
|
|
(3,799 |
) |
|
|
1,355 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Net commercial paper borrowings (repayments) |
|
|
2,340 |
|
|
|
(1,432 |
) |
Debt repayments |
|
|
|
|
|
|
(350 |
) |
Proceeds from stock option exercises |
|
|
96 |
|
|
|
15 |
|
Repurchases of common stock |
|
|
(1,290 |
) |
|
|
(430 |
) |
Dividends paid on common stock |
|
|
(140 |
) |
|
|
(142 |
) |
Excess tax benefits related to share-based compensation |
|
|
12 |
|
|
|
6 |
|
|
|
|
|
|
|
|
Net cash from financing activities |
|
|
1,018 |
|
|
|
(2,333 |
) |
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
32 |
|
|
|
(9 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
61 |
|
|
|
1,905 |
|
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale) |
|
|
3,290 |
|
|
|
1,011 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash related
to assets held for sale) |
|
$ |
3,351 |
|
|
$ |
2,916 |
|
|
|
|
|
|
|
|
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 2010 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 June 30, 2011 and Devons results of operations and cash flows for the
three-month and six-month periods ended June 30, 2011 and 2010.
Recently Issued Accounting Standards Not Yet Adopted
In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common
Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not
require additional fair value measurements and is not intended to establish valuation standards or
affect valuation practices outside of financial reporting. However, beginning in Devons 2011
Annual Report on Form 10-K, this update will require certain additional disclosures related to
Devons fair value measurements. Devon does not expect the adoption of this update will materially
impact its financial statement disclosures.
In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of
Comprehensive Income. Beginning in Devons 2011 Annual Report on Form 10-K, this update will give
Devon the option to present the total of comprehensive income, the components of net income and the
components of other comprehensive income either in a single continuous statement of comprehensive
income or in two separate but consecutive statements. Devon has not determined which presentation
option it will choose but does not expect its selection to materially impact the presentation of
its financial statements.
2. Short-Term Investments
Devon periodically invests excess cash in U.S. Treasury and other marketable securities that
are presented as short-term investments in the accompanying June 30, 2011 consolidated balance
sheet. During the first half of 2011, Devon invested a portion of the International offshore
divestiture proceeds it had received into United States Treasury securities, causing short-term
investments to increase. The carrying value of these investments approximates their fair value. As
of June 30, 2011, the average remaining maturity of these investments was 67 days, with a weighted
average yield of 0.06 percent.
3. Accounts Receivable
The components of accounts receivable include the following:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
|
(In millions) |
|
Oil, gas and NGL sales |
|
$ |
879 |
|
|
$ |
786 |
|
Joint interest billings |
|
|
245 |
|
|
|
204 |
|
Marketing and midstream revenues |
|
|
136 |
|
|
|
165 |
|
Other |
|
|
195 |
|
|
|
57 |
|
|
|
|
|
|
|
|
Gross accounts receivable |
|
|
1,455 |
|
|
|
1,212 |
|
Allowance for doubtful accounts |
|
|
(9 |
) |
|
|
(10 |
) |
|
|
|
|
|
|
|
Net accounts receivable |
|
$ |
1,446 |
|
|
$ |
1,202 |
|
|
|
|
|
|
|
|
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
4. Derivative Financial Instruments
Objectives and Strategies
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 exposure to interest rate volatility. Devon does not hold
or issue derivative financial instruments for speculative trading purposes and has elected not to
designate any of its derivative instruments for hedge accounting treatment.
Devons derivative financial instruments include financial price swaps, basis swaps, costless
price collars and call options. Under the terms of the price swaps, Devon receives a fixed price
for its production and pays a variable market price to the contract counterparty. For the basis
swaps, Devon receives a fixed differential between two regional gas index prices and pays a
variable differential on the same two index prices to the contract counterparty. The price collars
set a floor and ceiling price for the hedged production. If the applicable monthly price indices
are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will
cash-settle the difference with the counterparty to the collars. Under the terms of the call
options, Devon sold to counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate
volatility. Devons interest rate swaps include contracts in which Devon receives a fixed rate and
pays a variable rate on a total notional amount. Devon also had forward starting swaps and U.S.
Treasury locks. In conjunction with Devons debt issuance discussed in Note 7, Devon received $35
million from the net settlement of its forward starting swaps and U.S. Treasury locks in July 2011.
Counterparty Risk
By using derivative financial instruments to manage exposures to changes in commodity prices
and interest rates, Devon exposes itself to credit risk and market risk. Credit risk is the failure
of the counterparty to perform under the terms of the derivative contract. To mitigate this risk,
the hedging instruments are placed with a number of counterparties whom Devon believes are minimal
credit risks. It is Devons policy to enter into derivative contracts only with investment grade
rated counterparties deemed by management to be competent and competitive market makers.
Additionally, Devons derivative contracts generally require cash collateral to be posted if either
its 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 $55 million for the majority of
Devons contracts. As of June 30, 2011, the credit ratings of all Devons counterparties were
investment grade.
Commodity Derivatives
As of June 30, 2011, Devon had the following open oil derivative positions. Devons oil
derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures
price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
Period |
|
Price Swaps |
|
|
Price Collars |
|
|
Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
|
Volume |
|
|
Average Floor Price |
|
|
Average Ceiling Price |
|
|
Volume |
|
|
Average Price |
|
Period |
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
Q3-Q4 2011 |
|
|
|
|
|
|
|
|
|
|
45,000 |
|
|
$ |
75.00 |
|
|
$ |
108.89 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
Q1-Q4 2012 |
|
|
22,000 |
|
|
$ |
107.17 |
|
|
|
54,000 |
|
|
$ |
85.74 |
|
|
$ |
126.42 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
Q1-Q4 2013 |
|
|
|
|
|
|
|
|
|
|
7,000 |
|
|
$ |
90.00 |
|
|
$ |
125.12 |
|
|
|
|
|
|
|
|
|
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
As of June 30, 2011, Devon had the following open natural gas derivative positions. Devons
natural gas derivative swaps, collars and call options settle against the Inside Ferc first of the
month Henry Hub index.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
Period |
|
Price Swaps |
|
Price Collars |
|
Call Options Sold |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Volume |
|
Average Price |
|
Volume |
|
Average Floor Price |
|
Average Ceiling Price |
|
Volume |
|
Average Price |
Period |
|
(MMBtu/d) |
|
($/MMBtu) |
|
(MMBtu/d) |
|
($/MMBtu) |
|
($/MMBtu) |
|
(MMBtu/d) |
|
($/MMBtu) |
Q3-Q4 2011 |
|
|
712,500 |
|
|
$ |
5.51 |
|
|
|
215,000 |
|
|
|
4.75 |
|
|
|
5.17 |
|
|
|
|
|
|
|
|
|
Q1-Q4 2012 |
|
|
325,000 |
|
|
$ |
5.09 |
|
|
|
490,000 |
|
|
|
4.75 |
|
|
|
5.57 |
|
|
|
487,500 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
Differential to |
|
|
|
|
|
|
|
Volume |
|
|
Henry Hub |
|
Production Period |
|
Index |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Q3-Q4 2011 |
|
Panhandle Eastern Pipeline |
|
|
150,000 |
|
|
$ |
(0.33 |
) |
As of June 30, 2011, Devon had the following open NGL derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Basis Swaps |
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Volume |
|
Differential to WTI |
Production Period |
|
Pay |
|
(Bbls/d) |
|
($/Bbl) |
Q3-Q4 2011 |
|
Natural Gasoline |
|
|
416 |
|
|
$ |
(9.75 |
) |
Q1-Q4 2012 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
(10.10 |
) |
Q1-Q4 2013 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
(6.80 |
) |
Interest Rate Derivatives
As of June 30, 2011, Devon had the following open interest rate derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
July 7, 2011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury Locks |
|
|
|
|
Fixed Rate |
|
|
Variable |
|
|
|
|
Notional |
|
Paid |
|
|
Rate Received |
|
|
Expiration |
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
$350 |
|
|
|
1.56 |
% |
|
Five year U.S. Treasury |
|
July 6, 2011 |
300 |
|
|
|
2.96 |
% |
|
Ten year U.S. Treasury |
|
July 6, 2011 |
|
|
$650 |
|
|
2.21 |
% |
|
|
|
|
|
|
|
|
|
|
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Financial Statement Presentation
The following table presents the derivative fair values included in the accompanying
consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Caption |
|
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
|
|
|
|
|
(In millions) |
|
Asset derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Other current assets |
|
$ |
240 |
|
|
$ |
248 |
|
Commodity derivatives |
|
Other long-term assets |
|
|
81 |
|
|
|
1 |
|
Interest rate derivatives |
|
Other current assets |
|
|
78 |
|
|
|
100 |
|
Interest rate derivatives |
|
Other long-term assets |
|
|
33 |
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
Total asset derivatives |
|
|
|
|
|
$ |
432 |
|
|
$ |
389 |
|
|
|
|
|
|
|
|
|
|
|
|
Liability derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Other current liabilities |
|
$ |
83 |
|
|
$ |
50 |
|
Commodity derivatives |
|
Other long-term liabilities |
|
|
78 |
|
|
|
142 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liability derivatives |
|
|
|
|
|
$ |
161 |
|
|
$ |
192 |
|
|
|
|
|
|
|
|
|
|
|
|
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, 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 June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
$ |
59 |
|
|
$ |
252 |
|
|
$ |
145 |
|
|
$ |
348 |
|
Interest rate derivatives |
|
|
5 |
|
|
|
4 |
|
|
|
21 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
64 |
|
|
|
256 |
|
|
|
166 |
|
|
|
368 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
|
357 |
|
|
|
(207 |
) |
|
|
103 |
|
|
|
317 |
|
Interest rate derivatives |
|
|
(30 |
) |
|
|
(85 |
) |
|
|
(29 |
) |
|
|
(86 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) |
|
|
327 |
|
|
|
(292 |
) |
|
|
74 |
|
|
|
231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) recognized on
statement of operations |
|
$ |
391 |
|
|
$ |
(36 |
) |
|
$ |
240 |
|
|
$ |
599 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5. Other Current Assets
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011 |
|
|
December 31, 2010 |
|
|
|
(In millions) |
|
Derivative financial instruments |
|
$ |
318 |
|
|
$ |
348 |
|
Income taxes receivable |
|
|
206 |
|
|
|
270 |
|
Inventories |
|
|
137 |
|
|
|
120 |
|
Other |
|
|
50 |
|
|
|
41 |
|
|
|
|
|
|
|
|
Other current assets |
|
$ |
711 |
|
|
$ |
779 |
|
|
|
|
|
|
|
|
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
6. Goodwill
During the first six months of 2011, Devons Canadian goodwill increased $96 million entirely
due to foreign currency translation.
7. Debt
Credit Lines
Devon has a $2.7 billion syndicated, unsecured revolving line of credit (the Senior Credit
Facility). As of June 30, 2011, Devon had no borrowings under the Senior Credit Facility.
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 percent. The
credit agreement contains definitions of total funded debt and total capitalization that include
adjustments to the respective amounts reported in the consolidated financial statements. Also,
total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling
impairments or goodwill impairments. As of June 30, 2011, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at June 30, 2011, as calculated pursuant to the
terms of the agreement, was 19.3 percent.
Commercial Paper
In March 2011, Devons Board of Directors authorized an increase in its commercial paper
program from $2.2 billion to $5.0 billion. Commercial paper debt generally has a maturity of
between 1 and 90 days, although it can have a maturity of up to 365 days, and bears interest at
rates agreed to at the time of the borrowing. The interest rate is based on a standard index such
as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.
Although Devon ended the second quarter of 2011 with approximately $6.7 billion of cash and
short-term investments, the vast majority of this amount consists of proceeds from its
International divestitures. Based on Devons evaluation of future cash needs across its operations
in the United States and Canada, these proceeds remain outside of the United States.
Consequently, during the first six months of 2011, Devon borrowed $2.3 billion of commercial
paper in the United States primarily to fund capital expenditures, common stock repurchases and
dividends in excess of cash flow generated by its United States operating activities. As of June
30, 2011, Devons average borrowing rate on its $2.3 billion of commercial paper borrowings was
0.27 percent.
In July 2011, Devon received net proceeds totaling $2,224 million from the issuance of $500
million of 2.40% senior notes due July 15, 2016, $500 million of 4.00% senior notes due July 15,
2021 and $1,250 million of 5.60% senior notes due July 15, 2041. The net proceeds from issuance of
this long-term debt is being used to repay substantially all of Devons outstanding commercial
paper as of June 30, 2011 as it matures. Therefore, $2,224 million of Devons outstanding
commercial paper is classified as long-term debt in the accompanying June 30, 2011 consolidated
balance sheet.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
8. Asset Retirement Obligations
The schedule below summarizes changes in Devons asset retirement obligations.
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Asset retirement obligations as of beginning of period |
|
$ |
1,497 |
|
|
$ |
1,513 |
|
Liabilities incurred |
|
|
23 |
|
|
|
25 |
|
Liabilities settled |
|
|
(39 |
) |
|
|
(71 |
) |
Revision of estimated obligation |
|
|
16 |
|
|
|
194 |
|
Liabilities assumed by others |
|
|
|
|
|
|
(256 |
) |
Accretion expense on discounted obligation |
|
|
46 |
|
|
|
50 |
|
Foreign currency translation adjustment |
|
|
28 |
|
|
|
(14 |
) |
|
|
|
|
|
|
|
Asset retirement obligations as of end of period |
|
|
1,571 |
|
|
|
1,441 |
|
Less current portion |
|
|
72 |
|
|
|
95 |
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term |
|
$ |
1,499 |
|
|
$ |
1,346 |
|
|
|
|
|
|
|
|
During the first six months of 2010, Devon recognized a revision to its asset retirement
obligations totaling $194 million. The increase was primarily due to an overall increase in
abandonment cost estimates and a decrease in the discount rate used to calculate the present value
of the obligations.
During the first six months of 2010, Devon reduced its asset retirement obligations by $256
million for those obligations that were assumed by purchasers of Devons Gulf of Mexico oil and gas
properties in 2010.
9. Retirement Plans
Net Periodic Benefit Cost
The following table presents the components of net periodic benefit cost for Devons pension
and other postretirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Six Months |
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
9 |
|
|
$ |
8 |
|
|
$ |
18 |
|
|
$ |
16 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
|
|
Interest cost |
|
|
15 |
|
|
|
14 |
|
|
|
30 |
|
|
|
28 |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
Expected return on plan assets |
|
|
(11 |
) |
|
|
(9 |
) |
|
|
(21 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
Net actuarial loss |
|
|
8 |
|
|
|
7 |
|
|
|
16 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
22 |
|
|
$ |
21 |
|
|
$ |
45 |
|
|
$ |
42 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Plan Assets
Devon previously disclosed in its financial statements for the year ended December 31, 2010,
that it expected to contribute $84 million to its qualified pension plans in 2011. Devon now
expects to contribute $346 million to its qualified pension plans in 2011, including $246 million
that was contributed in the first six months of 2011 and $100 million that was contributed in July
2011. The increase in Devons 2011 contributions is due to increased discretionary funding.
As a result of the discretionary contributions noted above, Devon amended its target
allocation for its pension plan assets in the second quarter of 2011. Devon previously disclosed a
target allocation of 47.5% for equity securities, 40% for fixed
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
income and 12.5% for other investment types. Devon now expects an allocation of 70% fixed income,
20% equity and 10% for other investment types for its pension assets.
10. Stockholders Equity
Stock Repurchases
During the first six months of 2011, Devon repurchased 15.2 million common shares under its
$3.5 billion stock repurchase program announced in 2010 for $1.3 billion, or $84.52 per share. As
of June 30, 2011, Devon had repurchased 33.5 million common shares for $2.5 billion, or $74.16 per
share, under this program, which expires December 31, 2011.
Dividends
Devon paid common stock dividends of $140 million and $142 million in the first six months of
2011 and 2010, respectively. The quarterly cash dividend was $0.16 per share in the first and
second quarter of 2010 and the first quarter of 2011. In the second quarter of 2011, Devon
increased the dividend rate to $0.17 per share.
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 which 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 although
actual amounts could differ materially from managements estimate.
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.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation
activities associated with past operations, such as the Comprehensive Environmental Response,
Compensation, and Liability Act and similar state statutes. In response to liabilities associated
with these activities, loss accruals primarily consist of estimated costs associated with
remediation. Devons monetary exposure for environmental matters is not expected to be material.
Chief Redemption Matters
In 2006, Devon acquired Chief Holdings LLC (Chief) from the owners of Chief, including
Trevor Rees-Jones, the majority owner of Chief. In 2008, a former owner of Chief filed a petition
against Rees-Jones, as the former majority owner of Chief, and Devon, as Chiefs successor pursuant
to the 2006 acquisition. The petition claimed, among other things, violations of the Texas
Securities Act, fraud and breaches of Rees-Jones fiduciary responsibility to the former owner in
connection with Chiefs 2004 redemption of the owners minority ownership stake in Chief.
On June 20, 2011, a court issued a judgment against Rees-Jones for $196 million, of which $133
million of the judgment was also issued against Devon. Both Rees-Jones and Devon are appealing the
judgment. However, if the appeal is unsuccessful, Devon can and will seek full payment of the
judgment and any related interest, costs and expenses from Rees-Jones pursuant to an existing
indemnification agreement between Rees-Jones, certain other parties and Devon. Devon does not
expect to have any net exposure as a result of the judgment. However, because Devon does not have a
legal right of set
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
off with respect to the judgment, Devon has recorded in its June 30, 2011 consolidated balance
sheet both a $133 million liability relating to the judgment with an offsetting $133 million
receivable relating to its right to be indemnified by Rees-Jones and certain other parties pursuant
to the indemnification agreement.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business.
However, to Devons knowledge, there were no other material pending legal proceedings to which
Devon is a party or to which any of its property is subject.
Commitments
At the end of 2010, Devons commitments included approximately $0.6 billion related to lease
contracts for a deepwater drilling rig and a floating, production, storage and offloading facility
being used in Brazil. Devons remaining commitments for these leases were assumed by the buyer of
its assets upon closing the Brazil divestiture transaction discussed in Note 15.
12. Fair Value Measurements
Certain of Devons assets and liabilities are reported at fair value in the accompanying
consolidated balance sheets. Such assets and liabilities include amounts for both financial and
non-financial instruments. The following tables provide carrying value and fair value measurement
information for Devons financial assets and liabilities.
The carrying values of cash and cash equivalents, accounts receivable, other current
receivables, accounts payable and other current payables and accrued expenses included in the
accompanying consolidated balance sheets approximated fair value at June 30, 2011 and December 31,
2010. These assets and liabilities are not presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
Carrying |
|
Total Fair |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
|
Amount |
|
Value |
|
Inputs |
|
Inputs |
|
Inputs |
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
June 30, 2011 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
3,367 |
|
|
$ |
3,367 |
|
|
$ |
3,367 |
|
|
$ |
|
|
|
$ |
|
|
Long-term investments |
|
$ |
93 |
|
|
$ |
93 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
93 |
|
Commodity derivatives |
|
$ |
321 |
|
|
$ |
321 |
|
|
$ |
|
|
|
$ |
321 |
|
|
$ |
|
|
Commodity derivatives |
|
$ |
(161 |
) |
|
$ |
(161 |
) |
|
$ |
|
|
|
$ |
(161 |
) |
|
$ |
|
|
Interest rate derivatives |
|
$ |
111 |
|
|
$ |
111 |
|
|
$ |
|
|
|
$ |
111 |
|
|
$ |
|
|
Debt |
|
$ |
(7,930 |
) |
|
$ |
(8,867 |
) |
|
$ |
(2,340 |
) |
|
$ |
(6,423 |
) |
|
$ |
(104 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
Carrying |
|
Total Fair |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
|
Amount |
|
Value |
|
Inputs |
|
Inputs |
|
Inputs |
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
December 31, 2010 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
145 |
|
|
$ |
145 |
|
|
$ |
145 |
|
|
$ |
|
|
|
$ |
|
|
Long-term investments |
|
$ |
94 |
|
|
$ |
94 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
94 |
|
Commodity derivatives |
|
$ |
249 |
|
|
$ |
249 |
|
|
$ |
|
|
|
$ |
249 |
|
|
$ |
|
|
Commodity derivatives |
|
$ |
(192 |
) |
|
$ |
(192 |
) |
|
$ |
|
|
|
$ |
(192 |
) |
|
$ |
|
|
Interest rate derivatives |
|
$ |
140 |
|
|
$ |
140 |
|
|
$ |
|
|
|
$ |
140 |
|
|
$ |
|
|
Debt |
|
$ |
(5,630 |
) |
|
$ |
(6,629 |
) |
|
$ |
|
|
|
$ |
(6,485 |
) |
|
$ |
(144 |
) |
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Devons Level 3 fair value measurements included in the table above relate to certain
long-term investments and a non-interest bearing promissory note. Included below is a summary of
the changes in Devons Level 3 fair value measurements during the first six months of 2011 and
2010.
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Long-term investments balance at beginning of period |
|
$ |
94 |
|
|
$ |
115 |
|
Redemptions of principal |
|
|
(1 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
Long-term investments balance at end of period |
|
$ |
93 |
|
|
$ |
97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Debt balance at beginning of period |
|
$ |
(144 |
) |
|
$ |
|
|
Issuance of promissory note |
|
|
|
|
|
|
(139 |
) |
Foreign exchange translation adjustment |
|
|
(4 |
) |
|
|
|
|
Accretion of promissory note |
|
|
(2 |
) |
|
|
|
|
Redemptions of principal |
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
|
Debt balance at end of period |
|
$ |
(104 |
) |
|
$ |
(139 |
) |
|
|
|
|
|
|
|
13. Restructuring Costs
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of June
30, 2011, Devon had divested all of its U.S. Offshore assets and substantially all of its
International assets.
Through the end of the second quarter of 2011, Devon had incurred $204 million of
restructuring costs associated with these divestitures. This amount is comprised of $120 million of
employee severance costs, $81 million associated with abandoned office leases and $3 million of
other miscellaneous costs.
Financial Statement Presentation
The schedule below summarizes activity and balances associated with Devons restructuring
liabilities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
Discontinued Operations |
|
|
|
Other |
|
|
Other |
|
|
|
|
|
|
Other |
|
|
Other |
|
|
|
|
|
|
Current |
|
|
Long-Term |
|
|
|
|
|
|
Current |
|
|
Long-Term |
|
|
|
|
|
|
Liabilities |
|
|
Liabilities |
|
|
Total |
|
|
Liabilities |
|
|
Liabilities |
|
|
Total |
|
|
|
(In millions) |
|
Balance as of December 31, 2010 |
|
$ |
31 |
|
|
$ |
51 |
|
|
$ |
82 |
|
|
$ |
16 |
|
|
$ |
|
|
|
$ |
16 |
|
Cash severance settled |
|
|
(16 |
) |
|
|
|
|
|
|
(16 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
(4 |
) |
Lease obligations settled |
|
|
(1 |
) |
|
|
(7 |
) |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Lease obligations revision |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash severance revision |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
(2 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2011 |
|
$ |
14 |
|
|
$ |
43 |
|
|
$ |
57 |
|
|
$ |
10 |
|
|
$ |
|
|
|
$ |
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009 |
|
$ |
61 |
|
|
$ |
|
|
|
$ |
61 |
|
|
$ |
23 |
|
|
$ |
|
|
|
$ |
23 |
|
Cash severance settled |
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
Cash severance revision |
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2010 |
|
$ |
51 |
|
|
$ |
|
|
|
$ |
51 |
|
|
$ |
19 |
|
|
$ |
|
|
|
$ |
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The schedule below summarizes the components of restructuring costs in the accompanying 2011
and 2010 consolidated statement of operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2011 |
|
|
Six Months Ended June 30, 2011 |
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
|
(In millions) |
|
Cash severance |
|
$ |
1 |
|
|
$ |
(8 |
) |
|
$ |
(7 |
) |
|
$ |
1 |
|
|
$ |
(2 |
) |
|
$ |
(1 |
) |
Asset impairments |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Lease obligations |
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
|
(2 |
) |
|
|
|
|
|
|
(2 |
) |
Share-based awards |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
Other |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring costs |
|
$ |
6 |
|
|
$ |
(8 |
) |
|
$ |
(2 |
) |
|
$ |
1 |
|
|
$ |
(2 |
) |
|
$ |
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2010 |
|
|
Six Months Ended June 30, 2010 |
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
|
(In millions) |
|
Cash severance |
|
$ |
(5 |
) |
|
$ |
(3 |
) |
|
$ |
(8 |
) |
|
$ |
(5 |
) |
|
$ |
(3 |
) |
|
$ |
(8 |
) |
Share-based awards |
|
|
(4 |
) |
|
|
(2 |
) |
|
|
(6 |
) |
|
|
(4 |
) |
|
|
(2 |
) |
|
|
(6 |
) |
Other |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restructuring costs |
|
$ |
(8 |
) |
|
$ |
(5 |
) |
|
$ |
(13 |
) |
|
$ |
(8 |
) |
|
$ |
(5 |
) |
|
$ |
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14. Income Taxes
In the second quarter of 2011, a portion of Devons foreign earnings were no longer deemed to
be permanently reinvested in accordance with accounting principles generally accepted in the United
States of America. Accordingly, Devon recognized $725 million of deferred tax expense and $19
million of current income tax expense during the second quarter of 2011 related to assumed
repatriations of such earnings under current U.S. tax law. These earnings were primarily related to
the gains generated from Devons International divestiture transactions. Excluding the $744 million
of tax expense, Devons effective income tax rate was 33% in both the second quarter and first six
months of 2011, respectively.
15. Discontinued Operations
In May 2011, Devon completed the divestiture of its operations in Brazil. With the close of
the Brazil transaction, Devon has substantially completed its planned offshore divestitures. In
aggregate, Devons U.S. and International offshore sales have generated total proceeds of $10
billion, or approximately $8 billion after-tax, assuming repatriation of a portion of the foreign
proceeds under current U.S. tax law.
Revenues related to Devons discontinued operations totaled $43 million in the first six
months of 2011 and $222 million and $434 million in the second quarter and first six months of
2010, respectively. Devon did not have revenues related to its discontinued operations in the
second quarter of 2011.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Earnings from discontinued operations in the second quarter and first six months of 2011 and
2010 were largely impacted by gains on Devons International divestiture transactions. The
following table presents the gains on the divestitures according to the quarters in which the
divestitures closed in 2011 and 2010. The after-tax amounts in the table below exclude $744 million
of income tax expense related to assumed repatriations discussed in Note 14.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Quarter 2011 |
|
|
Third Quarter 2010 |
|
|
Second Quarter 2010 |
|
|
|
|
|
|
|
After |
|
|
|
|
|
|
After |
|
|
|
|
|
|
After |
|
|
|
Gross |
|
|
Taxes |
|
|
Gross |
|
|
Taxes |
|
|
Gross |
|
|
Taxes |
|
|
|
(In millions) |
|
Brazil |
|
$ |
2,546 |
|
|
$ |
2,546 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Azerbaijan |
|
|
|
|
|
|
|
|
|
|
1,543 |
|
|
|
1,524 |
|
|
|
|
|
|
|
|
|
China Panyu |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
308 |
|
|
|
235 |
|
Other |
|
|
|
|
|
|
|
|
|
|
(8 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,546 |
|
|
$ |
2,546 |
|
|
$ |
1,535 |
|
|
$ |
1,522 |
|
|
$ |
308 |
|
|
$ |
235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents the main classes of assets and liabilities associated with
Devons discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
424 |
|
Accounts receivable |
|
|
2 |
|
|
|
43 |
|
Other current assets |
|
|
34 |
|
|
|
96 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
36 |
|
|
$ |
563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
92 |
|
|
$ |
848 |
|
Other long-term assets |
|
|
2 |
|
|
|
11 |
|
|
|
|
|
|
|
|
Total long-term assets |
|
$ |
94 |
|
|
$ |
859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
4 |
|
|
$ |
260 |
|
Other current liabilities |
|
|
39 |
|
|
|
45 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
43 |
|
|
$ |
305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
2 |
|
|
$ |
26 |
|
|
|
|
|
|
|
|
16. Earnings Per Share
The following table reconciles earnings from continuing operations and common shares
outstanding used in the calculations of basic and diluted earnings per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common |
|
|
Earnings |
|
|
|
Earnings |
|
|
Shares |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended June 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
184 |
|
|
|
422 |
|
|
|
|
|
Attributable to participating securities |
|
|
(2 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
182 |
|
|
|
417 |
|
|
$ |
0.44 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
182 |
|
|
|
419 |
|
|
$ |
0.43 |
|
|
|
|
|
|
|
|
|
|
|
|
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common |
|
|
Earnings |
|
|
|
Earnings |
|
|
Shares |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
352 |
|
|
|
445 |
|
|
|
|
|
Attributable to participating securities |
|
|
(4 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
348 |
|
|
|
440 |
|
|
$ |
0.79 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
348 |
|
|
|
441 |
|
|
$ |
0.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
573 |
|
|
|
425 |
|
|
|
|
|
Attributable to participating securities |
|
|
(6 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
567 |
|
|
|
420 |
|
|
$ |
1.35 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
567 |
|
|
|
422 |
|
|
$ |
1.34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,426 |
|
|
|
446 |
|
|
|
|
|
Attributable to participating securities |
|
|
(17 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
1,409 |
|
|
|
441 |
|
|
$ |
3.20 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
1,409 |
|
|
|
442 |
|
|
$ |
3.19 |
|
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculation because the options are antidilutive. During the three-month and six-month periods
ended June 30, 2011, 3.1 million shares were excluded from the diluted earnings per share
calculations. During the three-month and six-month periods ended June 30, 2010, 7.9 million shares
and 6.4 million shares, respectively, were excluded from the diluted earnings per share
calculations.
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
17. Segment Information
Devon manages its North American onshore 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
businesses. However, Devons Canadian and International divisions are reported as separate
reporting segments primarily due to significant differences in the respective regulatory
environments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
As of June 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets (1) |
|
$ |
1,916 |
|
|
$ |
6,959 |
|
|
$ |
36 |
|
|
$ |
8,911 |
|
Property and equipment, net |
|
|
14,472 |
|
|
|
7,955 |
|
|
|
|
|
|
|
22,427 |
|
Goodwill |
|
|
3,046 |
|
|
|
3,130 |
|
|
|
|
|
|
|
6,176 |
|
Other assets |
|
|
538 |
|
|
|
391 |
|
|
|
94 |
|
|
|
1,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
19,972 |
|
|
$ |
18,435 |
|
|
$ |
130 |
|
|
$ |
38,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
1,995 |
|
|
$ |
2,446 |
|
|
$ |
43 |
|
|
$ |
4,484 |
|
Long-term debt |
|
|
4,725 |
|
|
|
1,243 |
|
|
|
|
|
|
|
5,968 |
|
Asset retirement obligations |
|
|
578 |
|
|
|
921 |
|
|
|
|
|
|
|
1,499 |
|
Other liabilities |
|
|
742 |
|
|
|
66 |
|
|
|
2 |
|
|
|
810 |
|
Deferred income taxes |
|
|
2,939 |
|
|
|
1,409 |
|
|
|
|
|
|
|
4,348 |
|
Stockholders equity |
|
|
8,993 |
|
|
|
12,350 |
|
|
|
85 |
|
|
|
21,428 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
19,972 |
|
|
$ |
18,435 |
|
|
$ |
130 |
|
|
$ |
38,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Current assets in the Canadian segment include $6.1 billion of cash, cash equivalents
and short-term investments that were generated from Devons International offshore
divestiture program and have not been repatriated to the United States. |
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended June 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
1,438 |
|
|
$ |
762 |
|
|
$ |
2,200 |
|
Oil, gas and NGL derivatives |
|
|
416 |
|
|
|
|
|
|
|
416 |
|
Marketing and midstream revenues |
|
|
554 |
|
|
|
50 |
|
|
|
604 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
2,408 |
|
|
|
812 |
|
|
|
3,220 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
224 |
|
|
|
229 |
|
|
|
453 |
|
Taxes other than income taxes |
|
|
107 |
|
|
|
13 |
|
|
|
120 |
|
Marketing and midstream operating costs and expenses |
|
|
413 |
|
|
|
43 |
|
|
|
456 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
291 |
|
|
|
194 |
|
|
|
485 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
59 |
|
|
|
6 |
|
|
|
65 |
|
Accretion of asset retirement obligations |
|
|
8 |
|
|
|
15 |
|
|
|
23 |
|
General and administrative expenses |
|
|
94 |
|
|
|
41 |
|
|
|
135 |
|
Restructuring costs |
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Interest expense |
|
|
40 |
|
|
|
45 |
|
|
|
85 |
|
Interest-rate and other financial instruments |
|
|
25 |
|
|
|
|
|
|
|
25 |
|
Other, net |
|
|
(7 |
) |
|
|
(4 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
1,260 |
|
|
|
582 |
|
|
|
1,842 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
1,148 |
|
|
|
230 |
|
|
|
1,378 |
|
Income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
35 |
|
|
|
1 |
|
|
|
36 |
|
Deferred |
|
|
1,100 |
|
|
|
58 |
|
|
|
1,158 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
1,135 |
|
|
|
59 |
|
|
|
1,194 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
13 |
|
|
$ |
171 |
|
|
$ |
184 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,499 |
|
|
$ |
334 |
|
|
$ |
1,833 |
|
|
|
|
|
|
|
|
|
|
|
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
1,144 |
|
|
$ |
638 |
|
|
$ |
1,782 |
|
Oil, gas and NGL derivatives |
|
|
32 |
|
|
|
13 |
|
|
|
45 |
|
Marketing and midstream revenues |
|
|
372 |
|
|
|
33 |
|
|
|
405 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,548 |
|
|
|
684 |
|
|
|
2,232 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
243 |
|
|
|
199 |
|
|
|
442 |
|
Taxes other than income taxes |
|
|
83 |
|
|
|
9 |
|
|
|
92 |
|
Marketing and midstream operating costs and expenses |
|
|
252 |
|
|
|
28 |
|
|
|
280 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
248 |
|
|
|
178 |
|
|
|
426 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
57 |
|
|
|
6 |
|
|
|
63 |
|
Accretion of asset retirement obligations |
|
|
12 |
|
|
|
12 |
|
|
|
24 |
|
General and administrative expenses |
|
|
98 |
|
|
|
32 |
|
|
|
130 |
|
Restructuring costs |
|
|
(8 |
) |
|
|
|
|
|
|
(8 |
) |
Interest expense |
|
|
55 |
|
|
|
56 |
|
|
|
111 |
|
Interest-rate and other financial instruments |
|
|
81 |
|
|
|
|
|
|
|
81 |
|
Other, net |
|
|
(26 |
) |
|
|
4 |
|
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
1,095 |
|
|
|
524 |
|
|
|
1,619 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
453 |
|
|
|
160 |
|
|
|
613 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
631 |
|
|
|
76 |
|
|
|
707 |
|
Deferred |
|
|
(421 |
) |
|
|
(25 |
) |
|
|
(446 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
210 |
|
|
|
51 |
|
|
|
261 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
243 |
|
|
$ |
109 |
|
|
$ |
352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,145 |
|
|
$ |
774 |
|
|
$ |
1,919 |
|
|
|
|
|
|
|
|
|
|
|
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Six Months Ended June 30, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
2,650 |
|
|
$ |
1,410 |
|
|
$ |
4,060 |
|
Oil, gas and NGL derivatives |
|
|
248 |
|
|
|
|
|
|
|
248 |
|
Marketing and midstream revenues |
|
|
977 |
|
|
|
82 |
|
|
|
1,059 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
3,875 |
|
|
|
1,492 |
|
|
|
5,367 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
432 |
|
|
|
445 |
|
|
|
877 |
|
Taxes other than income taxes |
|
|
201 |
|
|
|
27 |
|
|
|
228 |
|
Marketing and midstream operating costs and expenses |
|
|
721 |
|
|
|
68 |
|
|
|
789 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
551 |
|
|
|
376 |
|
|
|
927 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
117 |
|
|
|
12 |
|
|
|
129 |
|
Accretion of asset retirement obligations |
|
|
17 |
|
|
|
29 |
|
|
|
46 |
|
General and administrative expenses |
|
|
185 |
|
|
|
80 |
|
|
|
265 |
|
Restructuring costs |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Interest expense |
|
|
77 |
|
|
|
89 |
|
|
|
166 |
|
Interest-rate and other financial instruments |
|
|
8 |
|
|
|
|
|
|
|
8 |
|
Other, net |
|
|
(21 |
) |
|
|
(6 |
) |
|
|
(27 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
2,289 |
|
|
|
1,120 |
|
|
|
3,409 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
1,586 |
|
|
|
372 |
|
|
|
1,958 |
|
Income tax (benefit) expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(53 |
) |
|
|
|
|
|
|
(53 |
) |
Deferred |
|
|
1,343 |
|
|
|
95 |
|
|
|
1,438 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
1,290 |
|
|
|
95 |
|
|
|
1,385 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
296 |
|
|
$ |
277 |
|
|
$ |
573 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
2,749 |
|
|
$ |
866 |
|
|
$ |
3,615 |
|
Revision of future asset retirement obligations |
|
|
2 |
|
|
|
14 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
2,751 |
|
|
$ |
880 |
|
|
$ |
3,631 |
|
|
|
|
|
|
|
|
|
|
|
25
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
(In millions) |
|
Six Months Ended June 30, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
2,514 |
|
|
$ |
1,338 |
|
|
$ |
3,852 |
|
Oil, gas and NGL derivatives |
|
|
657 |
|
|
|
8 |
|
|
|
665 |
|
Marketing and midstream revenues |
|
|
868 |
|
|
|
67 |
|
|
|
935 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
4,039 |
|
|
|
1,413 |
|
|
|
5,452 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
467 |
|
|
|
389 |
|
|
|
856 |
|
Taxes other than income taxes |
|
|
173 |
|
|
|
20 |
|
|
|
193 |
|
Marketing and midstream operating costs and expenses |
|
|
621 |
|
|
|
56 |
|
|
|
677 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
509 |
|
|
|
343 |
|
|
|
852 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
113 |
|
|
|
13 |
|
|
|
126 |
|
Accretion of asset retirement obligations |
|
|
25 |
|
|
|
25 |
|
|
|
50 |
|
General and administrative expenses |
|
|
206 |
|
|
|
62 |
|
|
|
268 |
|
Restructuring costs |
|
|
(8 |
) |
|
|
|
|
|
|
(8 |
) |
Interest expense |
|
|
85 |
|
|
|
112 |
|
|
|
197 |
|
Interest-rate and other financial instruments |
|
|
66 |
|
|
|
|
|
|
|
66 |
|
Other, net |
|
|
(29 |
) |
|
|
3 |
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
2,228 |
|
|
|
1,023 |
|
|
|
3,251 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
1,811 |
|
|
|
390 |
|
|
|
2,201 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
845 |
|
|
|
161 |
|
|
|
1,006 |
|
Deferred |
|
|
(186 |
) |
|
|
(45 |
) |
|
|
(231 |
) |
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
659 |
|
|
|
116 |
|
|
|
775 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,152 |
|
|
$ |
274 |
|
|
$ |
1,426 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
2,189 |
|
|
$ |
1,144 |
|
|
$ |
3,333 |
|
Revision of future asset retirement obligations |
|
|
72 |
|
|
|
122 |
|
|
|
194 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
2,261 |
|
|
$ |
1,266 |
|
|
$ |
3,527 |
|
|
|
|
|
|
|
|
|
|
|
18. Supplemental Information to Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Net (increase) decrease in working capital: |
|
|
|
|
|
|
|
|
Increase in accounts receivable |
|
$ |
(100 |
) |
|
$ |
(1 |
) |
(Increase) decrease in other current assets |
|
|
(41 |
) |
|
|
44 |
|
Increase (decrease) in accounts payable |
|
|
9 |
|
|
|
(21 |
) |
Increase (decrease) in revenues and royalties due to others |
|
|
130 |
|
|
|
(21 |
) |
(Decrease) increase in other current liabilities |
|
|
(87 |
) |
|
|
580 |
|
|
|
|
|
|
|
|
Net (increase) decrease in working capital |
|
$ |
(89 |
) |
|
$ |
581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data total operations: |
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest) |
|
$ |
160 |
|
|
$ |
202 |
|
Income taxes (received) paid |
|
$ |
(125 |
) |
|
$ |
306 |
|
26
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses material changes in our results of operations
and capital resources and uses for the three-month and six-month periods ended June 30, 2011,
compared to the three-month and six-month periods ended June 30, 2010, and in our financial
condition and liquidity since December 31, 2010. For information regarding our critical accounting
policies and estimates, see our 2010 Annual Report on Form 10-K under Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations.
Financial Overview
During the second quarter and first six months of 2011, we generated net earnings of $2.7
billion, or $6.48 per diluted share, and $3.2 billion, or $7.41 per diluted share, for the
respective periods. This compares to net earnings of $706 million, or $1.58 per diluted share, and
$1.9 billion, or $4.24 per diluted share for the second quarter and first six months of 2010,
respectively. Our financial results for the second quarter and first six months of 2011 include an
after-tax gain of $1.8 billion related to International divestitures.
Key measures of our financial performance for the second quarter and first six months of 2011
compared to 2010 are summarized below. Our North America Onshore comparisons exclude amounts
related to our Gulf of Mexico assets that were divested in the first half of 2010.
|
|
|
North America Onshore oil and NGL production increased 7% to 20 MMBbls and 5% to 39
MMBbls in the second quarter and first six months of 2011, respectively. |
|
|
|
|
North America Onshore gas production increased 4% to 240 Bcf and 5% to 468 Bcf in the
second quarter and first six months of 2011, respectively. |
|
|
|
|
The combined realized price without hedges for oil, gas and NGLs increased 20% to $36.63
per Boe and 3% to $34.80 per Boe in the second quarter and first six months of 2011,
respectively. |
|
|
|
|
Oil, gas and NGL derivatives generated cash receipts of $59 million and $145 million for
the second quarter and first six months of 2011, respectively, and cash receipts of $252
million and $348 million in the second quarter and first six months of 2010, respectively. |
|
|
|
|
Marketing and midstream operating profit increased 19% to $148 million and 5% to $270
million in the second quarter and first six months of 2011, respectively. |
|
|
|
|
North America Onshore per unit operating costs increased 3% to $7.55 per Boe and 3% to
$7.52 per Boe in the second quarter and first six months of 2011, respectively. |
|
|
|
|
Operating cash flow increased 11% to $1.6 billion in the second quarter of 2011 and
decreased 3% to $2.8 billion in the first six months of 2011, respectively. |
|
|
|
|
Capital spending totaled approximately $3.7 billion in the first six months of 2011. |
In the second quarter of 2011, we completed the divestiture of our operations in Brazil. With
the close of the Brazil transaction, we have substantially completed our planned offshore
divestitures, generating aggregate after-tax proceeds of approximately $8 billion assuming
repatriation of a portion of the foreign proceeds under current U.S. tax law.
In July 2011, we issued $500 million of 2.40% senior notes due July 15, 2016, $500 million of
4.00% senior notes due July 15, 2021 and $1,250 million of 5.60% senior notes due July 15, 2041.
The net proceeds from issuance of this debt is being used to repay our outstanding commercial paper
as it matures.
Our performance and the proceeds from our previous offshore divestitures have allowed us to
maintain a robust level of liquidity. As of June 30, 2011, we held approximately $6.7 billion in
cash and short-term investments. We also have access to short-term commercial paper borrowings and
our $2.7 billion credit facility. With this liquidity, we continue executing our exploration and
development programs, with a focus on near-term growth of our liquids production, and repurchasing
common shares under our $3.5 billion share repurchase program. Through July 22, 2011, we had
repurchased 35.1 million shares for $2.6 billion, or $74.44 per share.
27
Second-Quarter Operating Highlights
|
|
|
In the Permian Basin, we increased production 17 percent over the second quarter of
2010, to 49 MBoe/d. Oil and natural gas liquids accounted for 75 percent of the
Permian Basins second quarter production. |
|
|
|
|
We completed nine operated Bone Spring wells within the Permian Basin in the second
quarter. Initial daily production from the nine wells averaged more than 700 Boe/d per
well. We have an average working interest of 77 percent in these wells. |
|
|
|
|
In Canada, we commenced steam injection and achieved first production from our
Jackfish 2 oil sands project in the second quarter. Production from the 100
percent-owned project is expected to ramp-up to 35 MBbls/d before royalties over the
next 18 months. |
|
|
|
|
Production from our Cana-Woodford Shale play averaged a record 189 MMcfe/d in the
second quarter, including nearly 9 MBbls/d of liquids. This represents an 80 percent
increase in total production compared to the year-ago quarter. |
|
|
|
|
Our Barnett Shale production increased 13 percent over the second-quarter 2010 to a
record 1.3 Bcfe/d, including 46 MBbls/d of liquids production. |
|
|
|
|
We brought 8 operated Granite Wash wells online in the second quarter. Initial
production from these wells averaged 2 MBoe/d, including 200 Bbls/d of oil and 730
Bbls/d of natural gas liquids. We have an average working interest of 71 percent in
these wells. |
|
|
|
|
We have assembled 1.1 million net acres targeting new oil and liquids-rich gas
opportunities across multiple basins in the U.S. In 2011, we plan to drill more than
30 wells targeting the Tuscaloosa Marine Shale, Niobrara Shale, Mississippian Lime,
Ohio Utica Shale and the A1 Carbonate and Utica Shale in Michigan. |
Results of Operations
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2011 |
|
2010 |
|
Change (1) |
|
2011 |
|
2010 |
|
Change (1) |
Oil Volumes (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
5 |
|
|
|
3 |
|
|
|
+27 |
% |
|
|
8 |
|
|
|
6 |
|
|
|
+26 |
% |
Canada |
|
|
6 |
|
|
|
6 |
|
|
|
-3 |
% |
|
|
13 |
|
|
|
13 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
11 |
|
|
|
9 |
|
|
|
+7 |
% |
|
|
21 |
|
|
|
19 |
|
|
|
+8 |
% |
U.S. Offshore |
|
|
|
|
|
|
1 |
|
|
|
-100 |
% |
|
|
|
|
|
|
2 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
11 |
|
|
|
10 |
|
|
|
0 |
% |
|
|
21 |
|
|
|
21 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Volumes (Bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
184 |
|
|
|
173 |
|
|
|
+6 |
% |
|
|
361 |
|
|
|
339 |
|
|
|
+7 |
% |
Canada |
|
|
56 |
|
|
|
58 |
|
|
|
-3 |
% |
|
|
107 |
|
|
|
108 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
240 |
|
|
|
231 |
|
|
|
+4 |
% |
|
|
468 |
|
|
|
447 |
|
|
|
+5 |
% |
U.S. Offshore |
|
|
|
|
|
|
7 |
|
|
|
-100 |
% |
|
|
|
|
|
|
17 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
240 |
|
|
|
238 |
|
|
|
+1 |
% |
|
|
468 |
|
|
|
464 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGLs Volumes (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
8 |
|
|
|
7 |
|
|
|
+20 |
% |
|
|
16 |
|
|
|
14 |
|
|
|
+18 |
% |
Canada |
|
|
1 |
|
|
|
1 |
|
|
|
-5 |
% |
|
|
2 |
|
|
|
2 |
|
|
|
-2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
9 |
|
|
|
8 |
|
|
|
+17 |
% |
|
|
18 |
|
|
|
16 |
|
|
|
+16 |
% |
U.S. Offshore |
|
|
|
|
|
|
|
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
9 |
|
|
|
8 |
|
|
|
+15 |
% |
|
|
18 |
|
|
|
16 |
|
|
|
+13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volumes (MMBoe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
43 |
|
|
|
39 |
|
|
|
+11 |
% |
|
|
84 |
|
|
|
76 |
|
|
|
+10 |
% |
Canada |
|
|
17 |
|
|
|
17 |
|
|
|
-3 |
% |
|
|
33 |
|
|
|
33 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
60 |
|
|
|
56 |
|
|
|
+6 |
% |
|
|
117 |
|
|
|
109 |
|
|
|
+7 |
% |
U.S. Offshore |
|
|
|
|
|
|
2 |
|
|
|
-100 |
% |
|
|
|
|
|
|
5 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
60 |
|
|
|
58 |
|
|
|
+3 |
% |
|
|
117 |
|
|
|
114 |
|
|
|
+2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
Six Months Ended June 30, |
|
|
2011 (1) |
|
2010 (1) |
|
Change |
|
2011 (1) |
|
2010 (1) |
|
Change |
Oil Prices (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
98.28 |
|
|
$ |
74.65 |
|
|
|
+32 |
% |
|
$ |
93.84 |
|
|
$ |
74.73 |
|
|
|
+26 |
% |
Canada |
|
$ |
73.65 |
|
|
$ |
54.43 |
|
|
|
+35 |
% |
|
$ |
67.29 |
|
|
$ |
58.36 |
|
|
|
+15 |
% |
North America Onshore |
|
$ |
83.31 |
|
|
$ |
61.11 |
|
|
|
+36 |
% |
|
$ |
77.32 |
|
|
$ |
63.67 |
|
|
|
+21 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
79.09 |
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
77.81 |
|
|
|
N/M |
|
Total |
|
$ |
83.31 |
|
|
$ |
62.35 |
|
|
|
+34 |
% |
|
$ |
77.32 |
|
|
$ |
64.93 |
|
|
|
+19 |
% |
Gas Prices (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
3.72 |
|
|
$ |
3.47 |
|
|
|
+7 |
% |
|
$ |
3.61 |
|
|
$ |
4.05 |
|
|
|
-11 |
% |
Canada |
|
$ |
4.08 |
|
|
$ |
3.99 |
|
|
|
+2 |
% |
|
$ |
4.05 |
|
|
$ |
4.50 |
|
|
|
-10 |
% |
North America Onshore |
|
$ |
3.80 |
|
|
$ |
3.60 |
|
|
|
+6 |
% |
|
$ |
3.71 |
|
|
$ |
4.16 |
|
|
|
-11 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
4.39 |
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
5.12 |
|
|
|
N/M |
|
Total |
|
$ |
3.80 |
|
|
$ |
3.62 |
|
|
|
+5 |
% |
|
$ |
3.71 |
|
|
$ |
4.19 |
|
|
|
-12 |
% |
NGLs Prices (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
40.43 |
|
|
$ |
28.73 |
|
|
|
+41 |
% |
|
$ |
38.04 |
|
|
$ |
31.39 |
|
|
|
+21 |
% |
Canada |
|
$ |
58.80 |
|
|
$ |
46.18 |
|
|
|
+27 |
% |
|
$ |
56.49 |
|
|
$ |
47.52 |
|
|
|
+19 |
% |
North America Onshore |
|
$ |
42.20 |
|
|
$ |
30.81 |
|
|
|
+37 |
% |
|
$ |
39.90 |
|
|
$ |
33.31 |
|
|
|
+20 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
35.59 |
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
38.22 |
|
|
|
N/M |
|
Total |
|
$ |
42.20 |
|
|
$ |
30.90 |
|
|
|
+37 |
% |
|
$ |
39.90 |
|
|
$ |
33.41 |
|
|
|
+19 |
% |
Combined Prices (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
33.19 |
|
|
$ |
26.77 |
|
|
|
+24 |
% |
|
$ |
31.53 |
|
|
$ |
29.71 |
|
|
|
+6 |
% |
Canada |
|
$ |
45.55 |
|
|
$ |
37.08 |
|
|
|
+23 |
% |
|
$ |
43.23 |
|
|
$ |
40.62 |
|
|
|
+6 |
% |
North America Onshore |
|
$ |
36.63 |
|
|
$ |
29.92 |
|
|
|
+22 |
% |
|
$ |
34.80 |
|
|
$ |
33.00 |
|
|
|
+5 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
46.17 |
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
49.06 |
|
|
|
N/M |
|
Total |
|
$ |
36.63 |
|
|
$ |
30.49 |
|
|
|
+20 |
% |
|
$ |
34.80 |
|
|
$ |
33.70 |
|
|
|
+3 |
% |
|
|
|
(1) |
|
The prices presented exclude any effects due to oil, gas and NGL derivatives. |
The volume and price changes in the tables above caused the following changes to our oil, gas
and NGL sales between the three months ended June 30, 2011 and 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2010 sales |
|
$ |
673 |
|
|
$ |
861 |
|
|
$ |
248 |
|
|
$ |
1,782 |
|
Changes due to volumes |
|
|
(1 |
) |
|
|
9 |
|
|
|
37 |
|
|
|
45 |
|
Changes due to prices |
|
|
225 |
|
|
|
43 |
|
|
|
105 |
|
|
|
373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 sales |
|
$ |
897 |
|
|
$ |
913 |
|
|
$ |
390 |
|
|
$ |
2,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The volume and price changes in the tables above caused the following changes to our oil, gas
and NGL sales between the six months ended June 30, 2011 and 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2010 sales |
|
$ |
1,383 |
|
|
$ |
1,947 |
|
|
$ |
522 |
|
|
$ |
3,852 |
|
Changes due to volumes |
|
|
(26 |
) |
|
|
17 |
|
|
|
70 |
|
|
|
61 |
|
Changes due to prices |
|
|
259 |
|
|
|
(227 |
) |
|
|
115 |
|
|
|
147 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 sales |
|
$ |
1,616 |
|
|
$ |
1,737 |
|
|
$ |
707 |
|
|
$ |
4,060 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales decreased $1 million and $26 million in the second quarter and first six months of 2011,
respectively, due to a decrease in production. The decreases were primarily due to the divestiture
of our U.S. Offshore properties in the second quarter of 2010, partially offset by increased North
America Onshore production of 7 percent and 8 percent, respectively. The increased North America
Onshore production in both periods resulted primarily from continued development of our Permian
Basin properties and increased production from our Jackfish thermal heavy oil project in Canada.
29
Oil sales increased $225 million and $259 million in the second quarter and first six
months of 2011, respectively, as a result of a 34 percent and 19 percent increase in our realized
price without hedges. The largest contributor to the increase in our realized prices was the
increase in the average West Texas Intermediate price over the same time period.
Gas Sales
A 1 percent increase in production during the second quarter and first six months of 2011
caused gas sales to increase by $9 million and $17 million, respectively. The increases were
comprised of the net effect of a 4 percent and 5 percent increase, respectively, in our North
America Onshore production, partially offset by the divestiture of our U.S. Offshore properties in
the second quarter of 2010. The increased North America Onshore production in both periods resulted
primarily from continued development activities in the Barnett and Cana-Woodford Shales, partially
offset by natural declines in our other operating areas.
Gas sales increased $43 million and decreased $227 million during the second quarter and first
six months of 2011, respectively, as a result of a 5 percent increase and a 12 percent decrease,
respectively, in our realized price without hedges. The changes in price were largely due to the
volatility of the North American regional index prices upon which our gas sales are based.
NGL Sales
NGL sales increased $37 million and $70 million during the second quarter and first six months
of 2011, respectively, due to a 15 percent increase and 13 percent increase in production. The
increased production in both periods was primarily due to increased drilling in our Barnett Shale,
Cana-Woodford Shale and Granite Wash locations.
NGL sales increased $105 million and $115 million during the second quarter and first six
months of 2011, respectively, due to a 37 percent and 19 percent increase in our realized price
without hedges. The increases were largely due to increases in the Mont Belvieu, Texas hub price
during the same time periods.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash receipts (payments): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas derivatives |
|
$ |
74 |
|
|
$ |
252 |
|
|
$ |
165 |
|
|
$ |
348 |
|
Oil derivatives |
|
|
(16 |
) |
|
|
|
|
|
|
(21 |
) |
|
|
|
|
NGL derivatives |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
59 |
|
|
|
252 |
|
|
|
145 |
|
|
|
348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas derivatives |
|
|
49 |
|
|
|
(331 |
) |
|
|
(8 |
) |
|
|
189 |
|
Oil derivatives |
|
|
308 |
|
|
|
124 |
|
|
|
110 |
|
|
|
128 |
|
NGL derivatives |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) |
|
|
357 |
|
|
|
(207 |
) |
|
|
103 |
|
|
|
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL derivatives |
|
$ |
416 |
|
|
$ |
45 |
|
|
$ |
248 |
|
|
$ |
665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2011 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
83.31 |
|
|
$ |
3.80 |
|
|
$ |
42.20 |
|
|
$ |
36.63 |
|
Cash settlements of hedges |
|
|
(1.49 |
) |
|
|
0.31 |
|
|
|
0.05 |
|
|
|
0.99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
81.82 |
|
|
$ |
4.11 |
|
|
$ |
42.25 |
|
|
$ |
37.62 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2010 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
62.35 |
|
|
$ |
3.62 |
|
|
$ |
30.90 |
|
|
$ |
30.49 |
|
Cash settlements of hedges |
|
|
|
|
|
|
1.06 |
|
|
|
|
|
|
|
4.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
62.35 |
|
|
$ |
4.68 |
|
|
$ |
30.90 |
|
|
$ |
34.80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2011 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
77.32 |
|
|
$ |
3.71 |
|
|
$ |
39.90 |
|
|
$ |
34.80 |
|
Cash settlements of hedges |
|
|
(1.00 |
) |
|
|
0.35 |
|
|
|
0.06 |
|
|
|
1.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
76.32 |
|
|
$ |
4.06 |
|
|
$ |
39.96 |
|
|
$ |
36.05 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
64.93 |
|
|
$ |
4.19 |
|
|
$ |
33.41 |
|
|
$ |
33.70 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.75 |
|
|
|
|
|
|
|
3.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
64.93 |
|
|
$ |
4.94 |
|
|
$ |
33.41 |
|
|
$ |
36.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our oil, gas and NGL derivatives include price swaps, costless collars and basis swaps. For
the price swaps, we receive a fixed price for our production and pay a variable market price to the
contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly
price indices are outside of the ranges set by the floor and ceiling prices in the various collars,
we cash-settle the difference with the counterparty to the collars. For the basis swaps, we receive
a fixed differential between two regional gas index prices and pay a variable differential on the
same two index prices to the contract counterparty. Cash settlements as presented in the tables
above represent realized gains or losses related to these various instruments.
Additionally, to enhance a portion of our natural gas price swaps, we have sold gas call
options for 2012 and oil call options for 2011 and 2012. The call options give counterparties the
right to purchase production at a predetermined price.
During the second quarter and first six months of 2011, we received $74 million, or $0.31 per
Mcf, and $165 million, or $0.35 per Mcf, respectively, from counterparties to settle our gas
derivatives and paid $16 million, or $1.49 per Bbl, and $21 million, or $1.00 per Bbl,
respectively, from counterparties to settle our oil derivatives. During the second quarter and
first six months of 2010, we received $252 million, or $1.06 per Mcf, and $348 million, or $0.75
per Mcf, respectively, from counterparties to settle our gas derivatives.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes
in the fair values of our oil, gas and NGL derivative instruments in each reporting period. We
estimate the fair values of these derivatives primarily by using internal discounted cash flow
calculations. 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
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
derivative financial instruments at June 30, 2011, a 10 percent increase in these forward curves
would have increased our unrealized losses by approximately $224 million. A 10 percent increase in
the forward curves associated with our oil derivatives would have decreased our unrealized gains by
approximately $300 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 production subject to oil, gas and NGL derivatives is not a variable in our cash flow
calculations, but it does impact the total derivative value.
Counterparty credit risk is also a component of commodity derivative valuations. We have
mitigated our exposure to any single counterparty by contracting with fourteen 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.
31
Such thresholds generally range from zero to $55 million for the majority of our contracts. As
of June 30, 2011, the credit ratings of all our counterparties were investment grade.
Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net
gains of $416 million and $248 million during the second quarter and first six months of 2011,
respectively. Including the cash settlements discussed above, our oil, gas and NGL derivatives
generated net gains of $45 million and $665 million during the second quarter and first six months
of 2010, respectively. In addition to the impact of cash settlements, these net gains and losses
were also impacted by new positions that occurred during each period, as well as the relationships
between contract prices and the associated forward curves. A summary of our outstanding oil, gas
and NGL derivative positions as of June 30, 2011 is included in Item 3. Quantitative and
Qualitative Disclosures About Market Risk of this report.
Marketing and Midstream Revenues and Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
Marketing and midstream: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
604 |
|
|
$ |
405 |
|
|
|
+49 |
% |
|
$ |
1,059 |
|
|
$ |
935 |
|
|
|
+13 |
% |
Operating costs and expenses |
|
|
456 |
|
|
|
280 |
|
|
|
+63 |
% |
|
|
789 |
|
|
|
677 |
|
|
|
+16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
148 |
|
|
$ |
125 |
|
|
|
+19 |
% |
|
$ |
270 |
|
|
$ |
258 |
|
|
|
+5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
During the second quarter of 2011, marketing and midstream revenues increased $199 million and
operating costs and expenses increased $176 million, causing operating profit to increase $23
million. During the first six months of 2011, marketing and midstream revenues increased $124
million and operating costs and expenses increased $112 million, causing operating profit to
increase $12 million. The increases in each period were primarily due to higher NGL prices and
higher natural gas throughput and NGL production.
Lease Operating Expenses (LOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
Lease operating expenses ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
224 |
|
|
$ |
216 |
|
|
|
+4 |
% |
|
$ |
432 |
|
|
$ |
407 |
|
|
|
+6 |
% |
Canada |
|
|
229 |
|
|
|
199 |
|
|
|
+15 |
% |
|
|
445 |
|
|
|
389 |
|
|
|
+14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
453 |
|
|
|
415 |
|
|
|
+9 |
% |
|
|
877 |
|
|
|
796 |
|
|
|
+10 |
% |
U.S. Offshore |
|
|
|
|
|
|
27 |
|
|
|
-100 |
% |
|
|
|
|
|
|
60 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
453 |
|
|
$ |
442 |
|
|
|
+3 |
% |
|
$ |
877 |
|
|
$ |
856 |
|
|
|
+3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
5.18 |
|
|
$ |
5.52 |
|
|
|
-6 |
% |
|
$ |
5.15 |
|
|
$ |
5.33 |
|
|
|
-3 |
% |
Canada |
|
$ |
13.71 |
|
|
$ |
11.53 |
|
|
|
+19 |
% |
|
$ |
13.63 |
|
|
$ |
11.80 |
|
|
|
+16 |
% |
North America Onshore |
|
$ |
7.55 |
|
|
$ |
7.36 |
|
|
|
+3 |
% |
|
$ |
7.52 |
|
|
$ |
7.28 |
|
|
|
+3 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
13.18 |
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
12.00 |
|
|
|
N/M |
|
Total |
|
$ |
7.55 |
|
|
$ |
7.56 |
|
|
|
0 |
% |
|
$ |
7.52 |
|
|
$ |
7.49 |
|
|
|
0 |
% |
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
LOE increased $11 million in the second quarter of 2011. This amount consisted of a $38
million increase related to our North America Onshore operations and a $27 million decrease related
to our U.S. Offshore operations that were sold in the second quarter of 2010. Our 6 percent
increase in North America Onshore production increased LOE by $27 million. Additionally, North
America Onshore LOE increased $14 million due to changes in the exchange rate between the U.S. and
Canadian dollars. The higher exchange rate was also the main contributor to the increases in North
America Onshore and total LOE per Boe.
LOE increased $21 million in the first six months of 2011. This amount consisted of an $81
million increase related to our North America Onshore operations and a $60 million decrease related
to our U.S. Offshore operations that were sold in the
32
second quarter of 2010. Our 7 percent increase in North America Onshore production increased
LOE by $54 million. Additionally, North America Onshore LOE increased $25 million due to changes in
the exchange rate between the U.S. and Canadian dollars. The higher exchange rate was also the main
contributor to the increases in North America Onshore and total LOE per Boe.
Taxes Other Than Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
|
|
|
|
|
|
|
|
|
($ in millions) |
|
|
|
|
|
|
|
|
|
Production |
|
$ |
68 |
|
|
$ |
46 |
|
|
|
+48 |
% |
|
$ |
124 |
|
|
$ |
105 |
|
|
|
+18 |
% |
Ad valorem |
|
|
51 |
|
|
|
46 |
|
|
|
+10 |
% |
|
|
101 |
|
|
|
86 |
|
|
|
+17 |
% |
Other |
|
|
1 |
|
|
|
|
|
|
|
+175 |
% |
|
|
3 |
|
|
|
2 |
|
|
|
+62 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
120 |
|
|
$ |
92 |
|
|
|
+30 |
% |
|
$ |
228 |
|
|
$ |
193 |
|
|
|
+18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
Production taxes increased $22 million and $19 million in the second quarter of 2011 and first
six months of 2011, respectively, primarily due to an increase in our U.S. Onshore revenues. Ad
valorem taxes increased $5 million and $15 million in the second quarter and first six months of
2011, respectively, primarily due to higher estimated assessed values of our oil and gas property
and equipment.
Depreciation, Depletion and Amortization of Oil and Gas Properties (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
Total production volumes (MMBoe) |
|
|
60 |
|
|
|
58 |
|
|
|
+3 |
% |
|
|
117 |
|
|
|
114 |
|
|
|
+2 |
% |
DD&A rate ($ per Boe) |
|
$ |
8.08 |
|
|
$ |
7.28 |
|
|
|
+11 |
% |
|
$ |
7.95 |
|
|
$ |
7.45 |
|
|
|
+7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
485 |
|
|
$ |
426 |
|
|
|
+14 |
% |
|
$ |
927 |
|
|
$ |
852 |
|
|
|
+9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
The following table details the changes in DD&A of oil and gas properties between the three
and six months ended June 30, 2011 and 2010 (in millions).
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
2010 DD&A |
|
$ |
426 |
|
|
$ |
852 |
|
Change due to rate |
|
|
48 |
|
|
|
58 |
|
Change due to volumes |
|
|
11 |
|
|
|
17 |
|
|
|
|
|
|
|
|
2011 DD&A |
|
$ |
485 |
|
|
$ |
927 |
|
|
|
|
|
|
|
|
Oil and gas property-related DD&A increased $48 million and $58 million in the second quarter
of 2011 and first six months of 2011, respectively, due to 11 percent and 7 percent increases in
the respective DD&A rates. The largest contributors to the higher rates were our drilling and
development activities subsequent to the end of the second quarter of 2010 and changes in the
exchange rate between the U.S. and Canadian dollars. These increases were partially offset by a
decrease in the rate due to our 2010 U.S. offshore property divestitures.
33
General and Administrative Expenses (G&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
Gross G&A |
|
$ |
245 |
|
|
$ |
240 |
|
|
|
+3 |
% |
|
$ |
483 |
|
|
$ |
485 |
|
|
|
0 |
% |
Capitalized G&A |
|
|
(81 |
) |
|
|
(81 |
) |
|
|
+1 |
% |
|
|
(162 |
) |
|
|
(161 |
) |
|
|
+1 |
% |
Reimbursed G&A |
|
|
(29 |
) |
|
|
(29 |
) |
|
|
0 |
% |
|
|
(56 |
) |
|
|
(56 |
) |
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
135 |
|
|
$ |
130 |
|
|
|
+4 |
% |
|
$ |
265 |
|
|
$ |
268 |
|
|
|
-1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
Gross and net G&A increased during the second quarter of 2011 primarily due to changes in the
exchange rate between the U.S. and Canadian dollars. Gross and net G&A decreased during the first
six months of 2011 primarily due to lower employee compensation and benefits resulting from our
2010 offshore divestitures.
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
100 |
|
|
$ |
104 |
|
|
$ |
198 |
|
|
$ |
209 |
|
Capitalized interest |
|
|
(17 |
) |
|
|
(14 |
) |
|
|
(37 |
) |
|
|
(35 |
) |
Early retirement of debt |
|
|
|
|
|
|
19 |
|
|
|
|
|
|
|
19 |
|
Other |
|
|
2 |
|
|
|
2 |
|
|
|
5 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense |
|
$ |
85 |
|
|
$ |
111 |
|
|
$ |
166 |
|
|
$ |
197 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense decreased during the second quarter and first six months of 2011 primarily
due to the early redemption of our 7.25 percent $350 million senior notes in the second quarter of
2010. When we redeemed these notes prior to their scheduled maturity, we recognized $19 million of
additional interest expense related to the early retirement of the debt.
Interest-Rate and Other Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
(Gains) losses from interest rate swaps: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash settlements |
|
$ |
(5 |
) |
|
$ |
(4 |
) |
|
$ |
(21 |
) |
|
$ |
(20 |
) |
Unrealized fair value changes |
|
|
30 |
|
|
|
85 |
|
|
|
29 |
|
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
25 |
|
|
$ |
81 |
|
|
$ |
8 |
|
|
$ |
66 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
During the second quarter and first six months of 2011, we received cash settlements totaling
$5 million and $21 million, respectively, from counterparties to settle our interest rate swaps.
During the second quarter and first six months of 2010, we received cash settlements totaling $4
million and $20 million, respectively.
In addition to recognizing cash settlements, we 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. During the second quarter and first six months of 2011, we
incurred unrealized losses of $30 million and $29 million, respectively, as a result of changes in
interest rates. During the second quarter and first six months of 2010, we incurred unrealized
losses of $85 million and $86 million, respectively.
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 Rate provided by a third party. Based on the
notional amount subject to the interest rate swaps at June 30, 2011, a 10% increase in these
forward curves would have decreased our unrealized losses for our interest rate swaps by
approximately $79 million.
34
Similar to 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 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 $55 million for the majority of our contracts. The credit ratings of all our
counterparties were investment grade as of June 30, 2011.
Income Taxes
The following table presents our total income tax expense and a reconciliation of our
effective income tax rate to the U.S. statutory income tax rate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Total income tax expense (in millions) |
|
$ |
1,194 |
|
|
$ |
261 |
|
|
$ |
1,385 |
|
|
$ |
775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
State income taxes |
|
|
1 |
% |
|
|
3 |
% |
|
|
1 |
% |
|
|
1 |
% |
Taxation on Canadian operations |
|
|
(2 |
%) |
|
|
(1 |
%) |
|
|
(2 |
%) |
|
|
(1 |
%) |
Assumed repatriations |
|
|
54 |
% |
|
|
8 |
% |
|
|
38 |
% |
|
|
2 |
% |
Other |
|
|
(1 |
%) |
|
|
(2 |
%) |
|
|
(1 |
%) |
|
|
(2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate |
|
|
87 |
% |
|
|
43 |
% |
|
|
71 |
% |
|
|
35 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
In the second quarter of 2011, a portion of our foreign earnings were no longer deemed to be
permanently reinvested in accordance with accounting principles generally accepted in the United
States of America. Accordingly, we recognized $725 million of deferred tax expense and $19 million
of current income tax expense during the second quarter of 2011 related to assumed repatriations of
such earnings under current U.S. tax law. These earnings were primarily related to the gains
generated from our International divestiture transactions. Excluding the $744 million of tax
expense, our effective income tax rate was 33% in both the second quarter and first six months of
2011.
In the second quarter of 2010, we recognized $52 million of deferred income tax expense
related to assumed repatriations of earnings from certain of our foreign subsidiaries. Excluding
the $52 million of deferred tax expense, our effective income tax rate was 35% and 33% in the
second quarter and first six months of 2010.
Earnings From Discontinued Operations
The following table presents the components of our earnings from discontinued operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Total production (MMBoe) |
|
|
|
|
|
|
3 |
|
|
|
1 |
|
|
|
6 |
|
Combined price without hedges (per Boe) |
|
$ |
|
|
|
$ |
74.45 |
|
|
$ |
81.94 |
|
|
$ |
73.56 |
|
|
|
(In millions) |
|
Operating revenues |
|
$ |
|
|
|
$ |
222 |
|
|
$ |
43 |
|
|
$ |
434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
7 |
|
|
|
56 |
|
|
|
33 |
|
|
|
133 |
|
Gain on sale of oil and gas properties |
|
|
(2,546 |
) |
|
|
(308 |
) |
|
|
(2,546 |
) |
|
|
(308 |
) |
Other, net |
|
|
(19 |
) |
|
|
1 |
|
|
|
(32 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
(2,558 |
) |
|
|
(251 |
) |
|
|
(2,545 |
) |
|
|
(176 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before income taxes |
|
|
2,558 |
|
|
|
473 |
|
|
|
2,588 |
|
|
|
610 |
|
Income tax (benefit) expense |
|
|
(1 |
) |
|
|
119 |
|
|
|
2 |
|
|
|
138 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
$ |
2,559 |
|
|
$ |
354 |
|
|
$ |
2,586 |
|
|
$ |
472 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
Earnings increased in the second quarter and first six months of 2011 primarily as a result of
the $2.5 billion gain ($2.5 billion after-tax) recognized from the divestiture of our Brazil
operations. This increase was partially offset by a $308 million gain ($235 million after taxes)
recognized from the divestiture of our Panyu operations in China during the second quarter of 2010.
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
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
2,830 |
|
|
$ |
2,619 |
|
Cash reclassified from discontinued operations |
|
|
3,251 |
|
|
|
450 |
|
Commercial paper borrowings |
|
|
2,340 |
|
|
|
|
|
Stock option exercises |
|
|
96 |
|
|
|
15 |
|
Divestitures of property and equipment |
|
|
5 |
|
|
|
4,129 |
|
Other |
|
|
13 |
|
|
|
24 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
8,535 |
|
|
|
7,237 |
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(3,720 |
) |
|
|
(3,221 |
) |
Net purchases of short-term investments |
|
|
(3,222 |
) |
|
|
|
|
Repurchases of common stock |
|
|
(1,290 |
) |
|
|
(430 |
) |
Dividends |
|
|
(140 |
) |
|
|
(142 |
) |
Commercial paper repayments |
|
|
|
|
|
|
(1,432 |
) |
Debt repayments |
|
|
|
|
|
|
(350 |
) |
Other |
|
|
(33 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(8,405 |
) |
|
|
(5,575 |
) |
|
|
|
|
|
|
|
Increase from continuing operations |
|
|
130 |
|
|
|
1,662 |
|
(Decrease) increase from discontinued operations, net of
reclassifications to continuing operations |
|
|
(101 |
) |
|
|
252 |
|
Effect of foreign exchange rates |
|
|
32 |
|
|
|
(9 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
$ |
61 |
|
|
$ |
1,905 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
3,351 |
|
|
$ |
2,916 |
|
|
|
|
|
|
|
|
Short-term investments at end of period |
|
$ |
3,367 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Operating Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash flow) continued to be a
significant source of capital and liquidity in the first six months of 2011. Our operating cash
flow increased approximately 8 percent during 2011 largely due to higher current income taxes in
2010 associated with taxable gains on our U.S. Offshore divestitures. Higher commodity prices and
production, partially offset by lower realized gains from our commodity derivatives, also
contributed to the increase in cash flow.
Other Sources of Cash Continuing and Discontinued Operations
As needed, we supplement our operating cash flow and available cash by accessing available
credit under our credit facilities and commercial paper program. We may also issue long-term debt
to supplement our operating cash flow while maintaining adequate liquidity under our credit
facilities. Additionally, we may acquire short-term investments to maximize our income on available
cash balances. As needed, we reduce such short-term investment balances to further supplement our
operating cash flow and available cash. Another source of cash proceeds comes from employee stock
option exercises.
During the second quarter of 2011, we completed the divestiture of our operations in Brazil,
generating $3.3 billion in net proceeds.
36
During the first six months of 2011, we utilized commercial paper borrowings of $2.3 billion
to fund capital expenditures, common share repurchases and dividends in excess of our operating
cash flow.
During the first six months of 2011, we received proceeds of $96 million from shares issued
for employee stock option exercises.
During the first six months of 2010, we completed the divestiture of all our U.S. Offshore
properties and our Panyu operations in China, generating $4.6 billion in pre-tax proceeds ($3.6
billion after taxes). We used proceeds from these divestitures to repay commercial paper
borrowings, retire $350 million of other debt and repurchase our common shares. In addition, we
redeployed $500 million of proceeds into our North America Onshore properties by acquiring a 50%
interest in the Pike oil sands in Alberta, Canada.
Capital Expenditures
Our capital expenditures are presented by geographic area and type in the following table. The
amounts in the table reflect cash payments for capital expenditures, including cash paid for
capital expenditures incurred in prior quarters. Capital expenditures actually incurred during the
first six months of 2011 and 2010 were approximately $3.6 billion and $3.3 billion, respectively.
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
2,375 |
|
|
$ |
1,468 |
|
Canada |
|
|
936 |
|
|
|
1,202 |
|
|
|
|
|
|
|
|
North America Onshore |
|
|
3,311 |
|
|
|
2,670 |
|
U.S. Offshore |
|
|
|
|
|
|
287 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
3,311 |
|
|
|
2,957 |
|
Midstream |
|
|
151 |
|
|
|
108 |
|
Other |
|
|
258 |
|
|
|
156 |
|
|
|
|
|
|
|
|
Total continuing operations |
|
$ |
3,720 |
|
|
$ |
3,221 |
|
|
|
|
|
|
|
|
Our capital expenditures
consist of amounts related to our oil and gas exploration and development operations, our midstream operations and
other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and
development of oil and gas properties, which totaled $3.3 billion and $3.0 billion in the first six months of 2011
and 2010, respectively. Excluding the $500 million Pike oil sands acquisition in 2010, the increase in exploration
and development capital spending in the first six months of 2011 was primarily due to increased drilling and development
and new venture acreage acquisitions. With rising oil prices and proceeds from our offshore divestitures, we are
increasing our acreage positions and associated exploration and development activities to drive near-term growth of
our onshore liquids production.
Capital expenditures for our midstream operations are primarily for the construction and
expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. Our
midstream capital expenditures are largely impacted by oil and gas drilling activities. Therefore,
the increase in development drilling also increased midstream capital activities.
Capital expenditures related to corporate activities increased in 2011. This increase is
largely driven by the construction of our new headquarters in Oklahoma City.
Short-term Investments
During the first six months of 2011, we had net short-term investment purchases totaling $3.2
billion. These purchases represent our investment of a portion of the International offshore
divestiture proceeds into United States Treasury securities. As of June 30, 2011, the average
remaining maturity of these short-term investments was 67 days.
37
Repurchases of Common Stock
During the first six months of 2011, we continued repurchasing shares under our $3.5 billion
stock repurchase program announced in May 2010. Including unsettled shares, we repurchased 15.2
million common shares for $1.3 billion, or $84.52 per share, in the first six months of 2011. This
program expires on December 31, 2011.
Dividends
We paid common stock dividends of $140 million and $142 million in the first six months of
2011 and 2010, respectively. The quarterly cash dividend was $0.16 per share in the first and
second quarter of 2010 and the first quarter of 2011. In the second quarter of 2011, we increased
the dividend rate to $0.17 per share.
Liquidity
Historically, our primary source of capital and liquidity has been operating cash flow and
cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program,
which can be accessed as needed to supplement operating cash flow and cash balances. Other
available sources of capital and liquidity include equity and debt securities that can be issued
pursuant to our automatically effective shelf registration statement filed with the SEC. We
estimate the combination of these sources of capital will be adequate to fund future capital
expenditures, share repurchases, debt repayments and other contractual commitments. The following
sections discuss changes to our liquidity subsequent to filing our 2010 Annual Report on Form 10-K.
Operating Cash Flow
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
swap, fixed-price physical delivery and price collar contracts to set minimum and maximum prices on
our 2011 production. As of June 30, 2011, approximately 38 percent of our 2011 gas production is
associated with financial price swaps, collars and fixed-price physicals. We also have basis swaps
associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36 percent
of our 2011 oil production is associated with financial price collars. We also have call options
that, if exercised, would relate to an additional 16 percent of our 2011 oil production.
Looking beyond 2011, we have also entered into contracts to manage the price risk relative to
our 2012 and 2013 oil, gas and NGL production. A summary of these contracts as of June 30, 2011, is
included in Item 3. Quantitative and Qualitative Disclosures About Market Risk of this report.
Offshore Divestitures
In May 2011, we completed the divestiture of our operations in Brazil. With the close of the
Brazil transaction, we have substantially completed our planned offshore divestitures. In
aggregate, our U.S. and International offshore sales generated total proceeds of $10 billion, or
approximately $8 billion after-tax assuming repatriation of a portion of the foreign proceeds under
current U.S. tax law.
Furthermore, in connection with the divestiture of our Brazil assets, our remaining deepwater
drilling rig and floating, production storage and offloading facility commitments were assumed by
the purchaser of the assets.
Credit Availability
In March 2011, our Board of Directors authorized an increase in our commercial paper program
from $2.2 billion to $5.0 billion.
In July 2011, we issued $500 million of 2.40% senior notes due July 15, 2016, $500 million of
4.00% senior notes due July 15, 2021 and $1,250 million of 5.60% senior notes due July 15, 2041.
The net proceeds from this issuance are being used to repay our outstanding commercial paper as it
matures. As of July 22, we had repaid $1.9 billion of commercial paper borrowings, and had $2.6
billion of available capacity under our syndicated, unsecured Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant. This covenant
requires us to maintain a ratio of total funded debt to total capitalization, as defined in the
credit agreement, of no more than 65 percent. The credit agreement
38
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 June 30,
2011, we were in compliance with this covenant. Our debt-to-capitalization ratio at June 30, 2011,
as calculated pursuant to the terms of the agreement, was 19.3 percent.
Although we ended the second quarter of 2011 with $6.7 billion of cash and short-term
investments, the vast majority of this amount consists of proceeds from our International offshore
divestitures. Based on our evaluation of future cash needs across our operations in the United
States and Canada, these proceeds remain outside of the United States. With these proceeds
remaining outside of the United States, we expect to continue to increase our commercial paper
borrowings in the United States to supplement our United States based operating cash flow to fund
our capital expenditures, common stock repurchase program and repay long-term debt.
Capital Expenditures
We previously disclosed that we expected our 2011 capital expenditures to range from $5.4
billion to $6.0 billion. In the first half of 2011, we expanded our Canadian, Permian Basin and new
ventures exploration activities, which were all targeted at oil and liquids-rich opportunities. We
also increased drilling activity in the liquids-rich portions of the Barnett and Cana shales.
Additionally, we are experiencing upward pressure on costs due to industry inflation and a weaker
U.S. dollar compared to the Canadian dollar. As a result, we increased our total estimated capital
expenditures. We now expect our 2011 capital expenditures to range from $6.7 billion to $7.3
billion. We anticipate having adequate capital resources to fund our capital expenditures.
Common Stock Repurchase Program
As of July 22, 2011, we had repurchased $2.6 billion, or 35.1 million common shares at an
average price of $74.44 under our $3.5 billion repurchase program. This program expires on December
31, 2011.
Pension Funding and Estimates
We previously disclosed that we expected to contribute approximately $84 million to our
qualified pension plans during 2011. We now expect to contribute $346 million to our qualified
pension plans in 2011, including $246 million that was contributed in the first six months of 2011
and $100 million that was contributed in July 2011. The increase in our 2011 estimated contribution
is due to discretionary funding.
Recently Issued Accounting Standards Not Yet Adopted
In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common
Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not
require additional fair value measurements and is not intended to establish valuation standards or
affect valuation practices outside of financial reporting. However, beginning in our 2011 Annual
Report on Form 10-K, this update will require certain additional disclosures related to our fair
value measurements. We do not expect the adoption of this update will materially impact our
financial statement disclosures.
In June 2011, the FASB issued Accounting Standards Update 2011-05, Presentation of
Comprehensive Income. Beginning in our 2011 Annual Report on Form 10-K, this update will give us
the option to present the total of comprehensive income, the components of net income and the
components of other comprehensive income either in a single continuous statement of comprehensive
income or in two separate but consecutive statements. We have not determined which presentation
option we will choose but do not expect our selection to materially impact the presentation of our
financial statements.
39
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have commodity derivatives that pertain to production for the last six months of 2011, as
well as 2012 and 2013. The key terms to all our oil, gas and NGL derivative financial instruments
as of June 30, 2011 are presented in the following tables.
We had the following open oil derivative positions. Our oil derivatives settle against the
average of the prompt month NYMEX West Texas Intermediate futures price.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
Period |
|
Price Swaps |
|
Price Collars |
|
Call Options Sold |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Volume |
|
Average Price |
|
Volume |
|
Average Floor Price |
|
Average Ceiling Price |
|
Volume |
|
Average Price |
Period |
|
(Bbls/d) |
|
($/Bbl) |
|
(Bbls/d) |
|
($/Bbl) |
|
($/Bbl) |
|
(Bbls/d) |
|
($/Bbl) |
Q3-Q4 2011 |
|
|
|
|
|
|
|
|
|
|
45,000 |
|
|
$ |
75.00 |
|
|
$ |
108.89 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
Q1-Q4 2012 |
|
|
22,000 |
|
|
$ |
107.17 |
|
|
|
54,000 |
|
|
$ |
85.74 |
|
|
$ |
126.42 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
Q1-Q4 2013 |
|
|
|
|
|
|
|
|
|
|
7,000 |
|
|
$ |
90.00 |
|
|
$ |
125.12 |
|
|
|
|
|
|
|
|
|
We had the following open natural gas derivative positions. Our natural gas derivative swaps,
collars and call options settle against the Inside Ferc first of the month Henry Hub index.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
Period |
|
Price Swaps |
|
|
|
|
|
Price Collars |
|
Call Options Sold |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
Weighted |
|
|
|
|
|
Weighted |
|
|
Volume |
|
Average Price |
|
Volume |
|
Average Floor Price |
|
Average Ceiling Price |
|
Volume |
|
Average Price |
Period |
|
(MMBtu/d) |
|
($/MMBtu) |
|
(MMBtu/d) |
|
($/MMBtu) |
|
($/MMBtu) |
|
(MMBtu/d) |
|
($/MMBtu) |
Q3-Q4 2011 |
|
|
712,500 |
|
|
$ |
5.51 |
|
|
|
215,000 |
|
|
|
4.75 |
|
|
|
5.17 |
|
|
|
|
|
|
|
|
|
Q1-Q4 2012 |
|
|
325,000 |
|
|
$ |
5.09 |
|
|
|
490,000 |
|
|
|
4.75 |
|
|
|
5.57 |
|
|
|
487,500 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps |
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
Differential to |
|
|
|
|
|
|
Volume |
|
Henry Hub |
Production Period |
|
Index |
|
(MMBtu/d) |
|
($/MMBtu) |
Q3-Q4 2011 |
|
Panhandle Eastern Pipeline |
|
|
150,000 |
|
|
$ |
(0.33 |
) |
We had the following open NGL derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Basis Swaps |
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Volume |
|
Differential to WTI |
Production Period |
|
Pay |
|
(Bbls/d) |
|
($/Bbl) |
Q3-Q4 2011 |
|
Natural Gasoline |
|
|
416 |
|
|
$ |
(9.75 |
) |
Q1-Q4 2012 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
(10.10 |
) |
Q1-Q4 2013 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
(6.80 |
) |
The fair values of our commodity derivatives presented in the tables above are largely
determined by estimates of the forward curves of the relevant price indices. At June 30, 2011, a 10
percent increase in the forward curves associated with our gas derivative instruments would have
increased our unrealized losses by approximately $224 million. A 10 percent increase in the forward
curves associated with our oil derivative instruments would have decreased our unrealized gains by
approximately $300 million.
Interest Rate Risk
At June 30, 2011, we had debt outstanding of $7.9 billion. Of this amount, $5.6 billion, or 70
percent bears fixed interest rates averaging 7.2 percent. Additionally, we had $2.3 billion of
outstanding commercial paper, bearing interest at floating rates which averaged 0.27 percent.
40
As of June 30, 2011, we had the open interest rate swap positions listed in the following
table. As of June 30, 2011, we also had forward starting swaps and U.S. Treasury locks that were
net settled in July 2011 in conjunction with our $2.25 billion debt issuance. We received $35
million to settle these derivatives.
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
% |
|
|
|
|
|
|
The fair values of our interest rate swaps are largely determined by estimates of the forward
curves of the Federal Funds rate and LIBOR. At June 30, 2011, a 10 percent increase in these
forward curves would have decreased our unrealized losses for our interest rate swaps by
approximately $79 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 percent unfavorable change in the
Canadian-to-U.S. dollar exchange rate would not materially impact our June 30, 2011 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 June 30, 2011, 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 second
quarter of 2011 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
41
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 2010 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 2010 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum Dollar Value |
|
|
Total Number |
|
|
|
|
|
of Shares that May Yet |
|
|
of Shares |
|
Average Price |
|
Be Purchased Under the |
2011 Period |
|
Purchased(1) |
|
Paid per Share |
|
Plans or Programs(1) |
|
|
|
|
|
|
|
|
|
|
(In millions) |
April 1 April 30 |
|
|
1,907,538 |
|
|
$ |
88.81 |
|
|
$ |
1,433 |
|
May 1 May 31 |
|
|
2,217,710 |
|
|
$ |
82.83 |
|
|
$ |
1,250 |
|
June 1 June 30 |
|
|
2,942,530 |
|
|
$ |
79.08 |
|
|
$ |
1,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
7,067,778 |
|
|
$ |
82.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In May 2010, our Board of Directors approved a $3.5 billion share repurchase
program. This program expires December 31, 2011. As of June 30, 2011, we had repurchased
33.5 million common shares for $2.5 billion, or $74.16 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 |
42
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: August 3, 2011 |
/s/ Jeffrey A. Agosta
|
|
|
Jeffrey A. Agosta |
|
|
Executive Vice President Chief Financial Officer |
|
43
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 |
44