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, 2008
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 No. 001-32318
Devon Energy Corporation
(Exact Name of Registrant as Specified in its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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73-1567067
(I.R.S. Employer
Identification Number) |
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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 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.
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Large accelerated filer þ |
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Accelerated filer o |
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Non-accelerated filer o
(Do not check if a smaller reporting company) |
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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
As of July 31, 2008, 441.8 million shares of the registrants common stock were outstanding.
[This page intentionally left blank.]
2
DEVON ENERGY CORPORATION
INDEX TO FORM 10-Q QUARTERLY REPORT
TO THE 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 that was
used to prepare the December 31, 2007 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; |
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production levels, including our Canadian production subject to government
royalties, which fluctuate with prices and production, and portions of our International
production governed by payout agreements which affect reported production; |
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reserve levels; |
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competitive conditions; |
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technology; |
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the availability of capital resources; |
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capital expenditure and other contractual obligations; |
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the supply and demand for oil, natural gas, NGLs and other energy products or services; |
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the price of oil, natural gas, NGLs and other energy products or services; |
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currency exchange rates, particularly the Canadian-to-U.S. dollar exchange rate; |
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the weather; |
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inflation; |
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the availability of goods and services; |
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drilling risks; |
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future processing volumes and pipeline throughput; |
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general economic conditions, whether internationally, nationally or in the
jurisdictions in which we or our subsidiaries conduct business; |
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legislative or regulatory changes, including retroactive royalty or production
tax regimes, changes in environmental regulation, environmental risks and liability
under federal, state and foreign environmental laws and regulations; |
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terrorism; |
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occurrence of property acquisitions or divestitures or the timing of such planned transactions; |
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the securities or capital markets and related risks such as general credit,
liquidity, market and interest-rate risks; and |
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other factors disclosed in Devons 2007 Annual Report on Form 10-K/A under Item
2. Properties Proved Reserves and Estimated Future Net Revenue, Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations, and Item 7A.
Quantitative and Qualitative Disclosures About Market Risk. |
All subsequent written and oral forward-looking statements attributable to Devon, or persons
acting on its
behalf, are expressly qualified in their entirety by the cautionary statements. We assume no
duty to update or revise our forward-looking statements based on changes in internal estimates or
expectations or otherwise.
4
DEFINITIONS
AS USED IN THIS DOCUMENT:
Bbl or Bbls means barrel or barrels.
Bcf means billion cubic feet.
Boe means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs
to six Mcf of gas.
Btu means British thermal units, a measure of heating value.
Federal Funds Rate means the interest rate that financial institutions charge each other for
the use of United States Treasury funds.
Inside FERC refers to the publication Inside F.E.R.C.s Gas Market Report.
LIBOR means London Interbank Offered Rate.
Mcf means thousand cubic feet.
MMBbls means million barrels.
MMBoe means million Boe.
MMBtu means million Btu.
Oil includes crude oil and condensate.
NGL or NGLs means natural gas liquids.
NYMEX means New York Mercantile Exchange.
SEC means United States Securities and Exchange Commission.
Domestic means the properties of Devon in the onshore continental United States and the
offshore Gulf of Mexico.
Canada means the division of Devon encompassing oil and gas properties located in Canada.
International means the division of Devon encompassing oil and gas properties that lie
outside the United States and Canada.
5
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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2008 |
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2007 |
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(Unaudited) |
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(In millions) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
1,837 |
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$ |
1,364 |
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Short-term investments, at fair value |
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1 |
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372 |
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Accounts receivable |
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2,460 |
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1,779 |
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Deferred income taxes |
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775 |
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44 |
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Current assets held for sale |
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105 |
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120 |
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Other current assets |
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255 |
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235 |
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Total current assets |
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5,433 |
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3,914 |
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Property and equipment, at cost, based on the full cost method of
accounting
for oil and gas properties ($3,741 and $3,417 excluded from amortization
in 2008 and 2007, respectively) |
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51,953 |
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48,473 |
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Less accumulated depreciation, depletion and amortization |
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21,769 |
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20,394 |
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30,184 |
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28,079 |
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Investment in Chevron Corporation common stock, at fair value |
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1,406 |
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1,324 |
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Goodwill |
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6,081 |
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6,172 |
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Long-term assets held for sale |
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84 |
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1,512 |
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Other long-term assets, including $126 million at fair value in 2008 |
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592 |
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455 |
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Total assets |
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$ |
43,780 |
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$ |
41,456 |
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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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$ |
1,525 |
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$ |
1,360 |
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Revenues and royalties due to others |
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966 |
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578 |
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Income taxes payable |
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306 |
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97 |
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Debentures exchangeable into shares of Chevron Corporation common stock |
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621 |
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Other short-term debt |
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1,004 |
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Derivative financial instruments, at fair value |
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2,125 |
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Current portion of asset retirement obligation, at fair value |
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63 |
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82 |
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Current liabilities associated with assets held for sale |
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16 |
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145 |
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Accrued expenses and other current liabilities |
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410 |
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391 |
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Total current liabilities |
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6,032 |
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3,657 |
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Debentures exchangeable into shares of Chevron Corporation common stock |
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641 |
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Other long-term debt |
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4,829 |
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6,283 |
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Derivative financial instruments, at fair value |
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83 |
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488 |
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Asset retirement obligation, at fair value |
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1,430 |
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1,236 |
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Long-term liabilities associated with assets held for sale |
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24 |
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404 |
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Other long-term liabilities |
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905 |
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699 |
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Deferred income taxes |
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7,044 |
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6,042 |
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Stockholders equity: |
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Preferred stock of $1.00 par value. Authorized 4.5 million shares;
issued 1.5 million shares ($150 million aggregate liquidation value)
in 2007 |
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1 |
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Common stock of $0.10 par value. Authorized 1.0 billion shares;
issued 444.9 million and 444.2 million shares in 2008 and 2007,
respectively |
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44 |
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44 |
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Additional paid-in capital |
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6,591 |
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6,743 |
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Retained earnings |
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14,717 |
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12,813 |
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Accumulated other comprehensive income |
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2,131 |
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2,405 |
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Treasury stock, at cost. 0.4 million shares in 2008 |
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(50 |
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Total stockholders equity |
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23,433 |
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22,006 |
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Commitments and contingencies (Note 8) |
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Total liabilities and stockholders equity |
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$ |
43,780 |
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$ |
41,456 |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
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2008 |
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2007 |
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2008 |
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2007 |
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(Unaudited) |
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(In millions, except per share amounts) |
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Revenues: |
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Oil sales |
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$ |
1,455 |
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$ |
865 |
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$ |
2,705 |
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$ |
1,556 |
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Gas sales |
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2,210 |
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1,366 |
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3,840 |
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2,612 |
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NGL sales |
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379 |
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224 |
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707 |
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401 |
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Net (loss) gain on oil and gas derivative financial instruments |
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(1,215 |
) |
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14 |
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(2,003 |
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(6 |
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Marketing and midstream revenues |
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719 |
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460 |
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1,274 |
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839 |
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Total revenues |
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3,548 |
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2,929 |
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6,523 |
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5,402 |
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Expenses and other income, net: |
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Lease operating expenses |
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537 |
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439 |
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1,043 |
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869 |
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Production taxes |
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176 |
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90 |
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310 |
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170 |
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Marketing and midstream operating costs and expenses |
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515 |
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341 |
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897 |
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611 |
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Depreciation, depletion and amortization of oil and gas properties |
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762 |
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645 |
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1,499 |
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1,232 |
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Depreciation and amortization of non-oil and gas properties |
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62 |
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49 |
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119 |
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95 |
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Accretion of asset retirement obligation |
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22 |
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18 |
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44 |
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36 |
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General and administrative expenses |
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180 |
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113 |
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328 |
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232 |
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Interest expense |
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90 |
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107 |
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192 |
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217 |
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Change in fair value of non-oil and gas derivative financial
instruments |
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(40 |
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(10 |
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(24 |
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(9 |
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Other income, net |
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(17 |
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(17 |
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(38 |
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(43 |
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Total expenses and other income, net |
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2,287 |
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1,775 |
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4,370 |
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3,410 |
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Earnings from continuing operations before income tax expense |
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1,261 |
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1,154 |
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2,153 |
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1,992 |
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Income tax expense: |
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Current |
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414 |
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174 |
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517 |
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363 |
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Deferred |
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253 |
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156 |
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391 |
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231 |
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Total income tax expense |
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667 |
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330 |
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908 |
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594 |
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Earnings from continuing operations |
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594 |
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824 |
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1,245 |
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1,398 |
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Discontinued operations: |
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Earnings from discontinued operations before income tax expense |
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851 |
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128 |
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1,040 |
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265 |
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Income tax expense |
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144 |
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48 |
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235 |
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108 |
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Earnings from discontinued operations |
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707 |
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80 |
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805 |
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157 |
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Net earnings |
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1,301 |
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904 |
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2,050 |
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1,555 |
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Preferred stock dividends |
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3 |
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3 |
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5 |
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5 |
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Net earnings applicable to common stockholders |
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$ |
1,298 |
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$ |
901 |
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$ |
2,045 |
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$ |
1,550 |
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Basic net earnings per share: |
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Earnings from continuing operations |
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$ |
1.33 |
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$ |
1.84 |
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$ |
2.79 |
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$ |
3.13 |
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Earnings from discontinued operations |
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1.58 |
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|
0.18 |
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1.80 |
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0.35 |
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Net earnings |
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$ |
2.91 |
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$ |
2.02 |
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$ |
4.59 |
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$ |
3.48 |
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Diluted net earnings per share: |
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Earnings from continuing operations |
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$ |
1.31 |
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$ |
1.82 |
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$ |
2.76 |
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$ |
3.09 |
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Earnings from discontinued operations |
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1.57 |
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|
0.18 |
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1.79 |
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|
0.35 |
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Net earnings |
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$ |
2.88 |
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$ |
2.00 |
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$ |
4.55 |
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$ |
3.44 |
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Weighted average common shares outstanding: |
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Basic |
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|
446 |
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|
446 |
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|
445 |
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|
445 |
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Diluted |
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450 |
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|
450 |
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|
450 |
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|
450 |
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See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
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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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2008 |
|
|
2007 |
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|
2008 |
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|
2007 |
|
|
|
(Unaudited) |
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|
(In millions) |
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Net earnings |
|
$ |
1,301 |
|
|
$ |
904 |
|
|
$ |
2,050 |
|
|
$ |
1,555 |
|
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cumulative translation adjustment |
|
|
88 |
|
|
|
649 |
|
|
|
(294 |
) |
|
|
732 |
|
Income tax benefit (expense) |
|
|
(3 |
) |
|
|
(35 |
) |
|
|
14 |
|
|
|
(41 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
85 |
|
|
|
614 |
|
|
|
(280 |
) |
|
|
691 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial loss and prior
service cost in net earnings |
|
|
4 |
|
|
|
4 |
|
|
|
9 |
|
|
|
8 |
|
Income tax expense |
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3 |
|
|
|
2 |
|
|
|
6 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income (loss), net of tax |
|
|
88 |
|
|
|
616 |
|
|
|
(274 |
) |
|
|
695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
1,389 |
|
|
$ |
1,520 |
|
|
$ |
1,776 |
|
|
$ |
2,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Total |
|
|
|
Preferred |
|
|
Common Stock |
|
|
Paid-In |
|
|
Retained |
|
|
Comprehensive |
|
|
Treasury |
|
|
Stockholders |
|
|
|
Stock |
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Income |
|
|
Stock |
|
|
Equity |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Six Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
$ |
1 |
|
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,743 |
|
|
$ |
12,813 |
|
|
$ |
2,405 |
|
|
$ |
|
|
|
$ |
22,006 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,050 |
|
|
|
|
|
|
|
|
|
|
|
2,050 |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(274 |
) |
|
|
|
|
|
|
(274 |
) |
Stock option exercises |
|
|
|
|
|
|
4 |
|
|
|
1 |
|
|
|
107 |
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
104 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(316 |
) |
|
|
(316 |
) |
Common stock retired |
|
|
|
|
|
|
(3 |
) |
|
|
(1 |
) |
|
|
(269 |
) |
|
|
|
|
|
|
|
|
|
|
270 |
|
|
|
|
|
Redemption of preferred stock |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(149 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(150 |
) |
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(141 |
) |
|
|
|
|
|
|
|
|
|
|
(141 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104 |
|
Excess tax
benefits on share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2008 |
|
$ |
|
|
|
|
445 |
|
|
$ |
44 |
|
|
$ |
6,591 |
|
|
$ |
14,717 |
|
|
$ |
2,131 |
|
|
$ |
(50 |
) |
|
$ |
23,433 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006 |
|
$ |
1 |
|
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,840 |
|
|
$ |
9,114 |
|
|
$ |
1,444 |
|
|
$ |
(1 |
) |
|
$ |
17,442 |
|
Adoption of FASB Statement No. 159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
364 |
|
|
|
(364 |
) |
|
|
|
|
|
|
|
|
Adoption of FASB Interpretation No. 48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
Adoption of FASB Statement No. 158 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
16 |
|
|
|
|
|
|
|
15 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,555 |
|
|
|
|
|
|
|
|
|
|
|
1,555 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
695 |
|
|
|
|
|
|
|
695 |
|
Stock option exercises |
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
(16 |
) |
Common stock retired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(124 |
) |
|
|
|
|
|
|
|
|
|
|
(124 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
57 |
|
Excess tax
benefits on share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of June 30, 2007 |
|
$ |
1 |
|
|
|
446 |
|
|
$ |
45 |
|
|
$ |
6,956 |
|
|
$ |
10,893 |
|
|
$ |
1,791 |
|
|
$ |
|
|
|
$ |
19,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
2,050 |
|
|
$ |
1,555 |
|
Earnings from discontinued operations, net of tax |
|
|
(805 |
) |
|
|
(157 |
) |
Adjustments to reconcile earnings from continuing operations
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
1,618 |
|
|
|
1,327 |
|
Deferred income tax expense |
|
|
391 |
|
|
|
231 |
|
Net unrealized loss on oil and gas derivative financial instruments |
|
|
1,692 |
|
|
|
23 |
|
Other noncash charges |
|
|
122 |
|
|
|
71 |
|
(Increase) decrease in assets: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(604 |
) |
|
|
32 |
|
Other current assets |
|
|
(44 |
) |
|
|
(27 |
) |
Other long-term assets |
|
|
(40 |
) |
|
|
(46 |
) |
Increase (decrease) in liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
|
120 |
|
|
|
64 |
|
Revenues and royalties due to others |
|
|
348 |
|
|
|
(17 |
) |
Income taxes payable |
|
|
136 |
|
|
|
178 |
|
Other current liabilities |
|
|
(99 |
) |
|
|
(96 |
) |
Other long-term liabilities |
|
|
181 |
|
|
|
14 |
|
|
|
|
|
|
|
|
Cash provided by operating activities continuing operations |
|
|
5,066 |
|
|
|
3,152 |
|
Cash provided by operating activities discontinued operations |
|
|
120 |
|
|
|
197 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
5,186 |
|
|
|
3,349 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from sales of property and equipment |
|
|
108 |
|
|
|
37 |
|
Capital expenditures |
|
|
(3,867 |
) |
|
|
(2,990 |
) |
Purchases of short-term investments |
|
|
(50 |
) |
|
|
(589 |
) |
Redemptions of short-term and long-term investments |
|
|
295 |
|
|
|
848 |
|
|
|
|
|
|
|
|
Cash used in investing activities continuing operations |
|
|
(3,514 |
) |
|
|
(2,694 |
) |
Cash provided by (used in) investing activities discontinued operations |
|
|
1,709 |
|
|
|
(115 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(1,805 |
) |
|
|
(2,809 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Credit facility repayments |
|
|
(3,070 |
) |
|
|
|
|
Credit facility borrowings |
|
|
1,620 |
|
|
|
|
|
Net commercial paper repayments |
|
|
(1,004 |
) |
|
|
(183 |
) |
Principal payments on debt |
|
|
(47 |
) |
|
|
|
|
Preferred stock redemption |
|
|
(150 |
) |
|
|
|
|
Proceeds from stock option exercises |
|
|
104 |
|
|
|
60 |
|
Repurchases of common stock |
|
|
(252 |
) |
|
|
(10 |
) |
Dividends paid on common and preferred stock |
|
|
(146 |
) |
|
|
(129 |
) |
Excess tax benefits related to share-based compensation |
|
|
55 |
|
|
|
17 |
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(2,890 |
) |
|
|
(245 |
) |
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
(19 |
) |
|
|
16 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
472 |
|
|
|
311 |
|
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale) |
|
|
1,373 |
|
|
|
756 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash related
to assets held for sale) |
|
$ |
1,845 |
|
|
$ |
1,067 |
|
|
|
|
|
|
|
|
Supplementary cash flow data: |
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest) |
|
$ |
189 |
|
|
$ |
202 |
|
Income taxes paid continuing and discontinued operations |
|
$ |
826 |
|
|
$ |
159 |
|
See accompanying notes to consolidated financial statements.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
The accompanying unaudited consolidated financial statements and notes of Devon Energy
Corporation (Devon) have been prepared pursuant to the rules and regulations of the United States
Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures
normally included in financial statements prepared in accordance with accounting principles
generally accepted in the United States of America have been omitted. The accompanying consolidated
financial statements and notes should be read in conjunction with the consolidated financial
statements and notes included in Devons 2007 Annual Report on Form 10-K/A.
The unaudited interim consolidated financial statements furnished in this report reflect all
adjustments which are, in the opinion of management, necessary to a fair statement of Devons
financial position as of June 30, 2008 and Devons results of operations and cash flows for the
three-month and six-month periods ended June 30, 2008 and 2007. Except for the reclassification of
auction rate securities discussed below, all such adjustments are of a normal recurring nature.
Reclassification of Auction Rate Securities
At December 31, 2007, Devon held $372 million of auction rate securities. Such securities are
rated AAAthe highest ratingby one or more rating agencies and are collateralized by student loans
that are substantially guaranteed by the United States government. Although Devons auction rate
securities generally have contractual maturities of more than 20 years, the underlying interest
rates on such securities are scheduled to reset every seven to 28 days. Therefore, these auction
rate securities were generally priced and subsequently traded as short-term investments because of
the interest rate reset feature. As a result, Devon classified its auction rate securities as
short-term investments in the accompanying December 31, 2007 consolidated balance sheet and in
prior periods.
During the first half of 2008, Devon reduced its auction rate securities holdings to $127
million. However, since February 8, 2008 Devon has experienced difficulty selling its securities
due to the failure of the auction mechanism, which provides liquidity to these securities. An
auction failure means that the parties wishing to sell securities could not do so. The securities
for which auctions have failed will continue to accrue interest and be auctioned every seven to 28
days until the auction succeeds, the issuer calls the securities or the securities mature.
From February 2008, when auctions began failing, to June 30, 2008, issuers redeemed $26
million of Devons auction rate securities holdings at par. Additionally, Devons auction rate
securities holdings as of June 30, 2008 include approximately $1 million of securities that were
called at par value by the issuer and were repaid on July 10, 2008. These called securities are
classified as short-term investments in the accompanying June 30, 2008 consolidated balance sheet.
However, based on continued auction failures and the current market for Devons auction rate
securities, Devon has classified the $126 million of securities that have not been called as of
June 30, 2008 as long-term investments. These securities are included in other long-term assets in
the accompanying June 30, 2008 consolidated balance sheet. Devon has the ability to hold the
securities until maturity. At this time, Devon does not believe the values of its long-term
securities are impaired.
Recently Issued Accounting Standards Not Yet Adopted
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 141(R), Business Combinations, which replaces Statement No. 141.
Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be
identified and the acquisition method of accounting (previously called the purchase method) be used
for all business combinations. Statement No. 141(R)s scope is broader than that of Statement No.
141, which applied only to business combinations in which control was obtained by transferring
consideration. By applying the acquisition method to all transactions and other events in which one
entity obtains control over one or more other businesses, Statement No. 141(R) improves the
comparability of the information about business combinations provided in financial reports.
Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and
measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the
acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. Devon will evaluate how the new
requirements of Statement No. 141(R) would impact any business combinations completed in 2009 or
thereafter.
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160,
Noncontrolling Interests in Consolidated Financial Statementsan amendment of Accounting Research
Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of
equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160
establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a
subsidiary must be reported as a component of consolidated equity separate from the parents
equity. Additionally, the amounts of consolidated net income attributable to both the parent and
the noncontrolling interest must be reported separately on the face of the income statement.
Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier
adoption is prohibited. Devon does not expect the adoption of Statement No. 160 to have a material
impact on its financial statements and related disclosures.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,
Disclosures about Derivative Instruments and Hedging Activitiesan amendment of FASB Statement No.
133. Statement No. 161 requires additional disclosures about derivative and hedging activities and
is effective for fiscal years and interim periods beginning after November 15, 2008. Devon is
evaluating the impact the adoption of Statement No. 161 will have on its financial statement
disclosures. However, Devons adoption of Statement No. 161 will not affect its current accounting
for derivative and hedging activities.
2. Property and Equipment and Asset Retirement Obligations
Divestitures
Near the beginning of 2007, Devon announced plans to sell its assets and terminate its
operations located in Africa. This divestiture package consisted primarily of Devons operations
located in Egypt and the West African countries of Equatorial Guinea, Gabon and Cote DIvoire.
Additional information regarding Devons Egyptian and West African operations, which are presented
as discontinued in the accompanying financial statements, is provided in Note 12.
Asset Retirement Obligations (ARO)
The following is a summary of the changes in Devons ARO for the first six months of 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Asset retirement obligation as of beginning of period |
|
$ |
1,318 |
|
|
$ |
857 |
|
Liabilities incurred |
|
|
29 |
|
|
|
32 |
|
Liabilities settled |
|
|
(40 |
) |
|
|
(24 |
) |
Revision of estimated obligation |
|
|
162 |
|
|
|
311 |
|
Accretion expense on discounted obligation |
|
|
44 |
|
|
|
36 |
|
Foreign currency translation adjustment |
|
|
(20 |
) |
|
|
47 |
|
|
|
|
|
|
|
|
Asset retirement obligation as of end of period |
|
|
1,493 |
|
|
|
1,259 |
|
Less current portion |
|
|
63 |
|
|
|
45 |
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
1,430 |
|
|
$ |
1,214 |
|
|
|
|
|
|
|
|
During the first six months of 2008 and 2007, Devon recognized increases of $162 million and
$311 million, respectively, to its ARO. The primary factors causing the 2008 fair value increase
were an overall increase in abandonment cost estimates and the effect of a decrease in the discount
rate used to present value the obligations. The primary factors causing the 2007 fair value
increase were an overall increase in abandonment cost estimates and an increase in the assumed
inflation rate.
3. Commodity Derivative Financial Instruments
Devon periodically enters into derivative financial instruments with respect to a portion of
its oil and gas production that hedge the future prices received. These instruments are used to
manage the inherent uncertainty of future revenues due to oil and gas price volatility. Devons
derivative financial instruments include financial price swaps, whereby Devon will receive a fixed
price for its production and pay a variable market price to the contract counterparty, and costless
price collars that set a floor and ceiling price for |
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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.
As discussed more fully in Note 1 to the consolidated financial statements in Devons 2007
Annual Report on Form 10-K/A, Devons derivative financial instruments are recognized at the
current fair value on the balance sheet. Unrealized changes in such fair values are recorded in the
statement of operations. Cash settlements with counterparties to Devons price swaps and price
collars are also recorded in the statement of operations.
The following tables present the fair values included in the accompanying balance sheet and
the cash settlements and net unrealized losses included in the accompanying statement of operations
associated with Devons commodity derivative financial instruments.
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008 |
|
|
December 31, 2007 |
|
|
|
(In millions) |
|
Fair values: |
|
|
|
|
|
|
|
|
Other current assets gas price swaps |
|
$ |
|
|
|
$ |
12 |
|
Derivative financial instruments, current liability: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
606 |
|
|
$ |
|
|
Gas price collars |
|
|
945 |
|
|
|
|
|
Oil price collars |
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative financial instruments, current liability |
|
$ |
1,597 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Derivative financial instruments, long-term liability: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
|
|
|
$ |
|
|
Gas price collars |
|
|
83 |
|
|
|
|
|
Oil price collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative financial instruments, long-term liability |
|
$ |
83 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
(153 |
) |
|
$ |
5 |
|
|
$ |
(161 |
) |
|
$ |
15 |
|
Gas price collars |
|
|
(150 |
) |
|
|
|
|
|
|
(150 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received |
|
|
(303 |
) |
|
|
5 |
|
|
|
(311 |
) |
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (losses) gains on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
(247 |
) |
|
|
9 |
|
|
|
(618 |
) |
|
|
(19 |
) |
Gas price collars |
|
|
(620 |
) |
|
|
|
|
|
|
(1,028 |
) |
|
|
(4 |
) |
Oil price collars |
|
|
(45 |
) |
|
|
|
|
|
|
(46 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized (losses) gains on fair value
changes |
|
|
(912 |
) |
|
|
9 |
|
|
|
(1,692 |
) |
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) gain on oil and gas derivative financial
instruments |
|
$ |
(1,215 |
) |
|
$ |
14 |
|
|
$ |
(2,003 |
) |
|
$ |
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
4. Debt
Credit Facilities
In April 2008, Devon extended the maturity of $2.0 billion of its existing $2.5 billion
five-year, syndicated, unsecured revolving line of credit (the Senior Credit
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Facility) from April 7, 2012 to April
7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not approve a maturity
date extension. Therefore, the maturity date for $0.5 billion of the Senior Credit Facility remains
at April 7, 2012.
During the second quarter of 2008, Devon repaid $2.5 billion of outstanding commercial paper
and Senior Credit Facility borrowings primarily with proceeds received from the sales of assets in
West Africa and cash generated from operations.
On August 7, 2007, Devon established a $1.5 billion 364-day, syndicated, unsecured revolving
senior credit facility (the Short-Term Facility). This facility matured on August 5, 2008 and was
not extended. As a result of the Short-Term Facilitys maturity, Devons commercial paper program
capacity decreased from $3.5 billion to $2.0 billion.
The Senior Credit Facility contains only one material financial covenant. This covenant
requires Devon to maintain a ratio of total funded debt to total capitalization, as defined in the
credit agreement, of no more than 65%. As of June 30, 2008, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at June 30, 2008, as calculated pursuant to the
terms of the agreement, was 16.3%.
As of August 5, 2008, Devons available capacity under its Senior Credit Facility was
approximately $2.4 billion. This available capacity is net of $140 million of outstanding letters
of credit. There were no outstanding commercial paper or Senior Credit Facility borrowings as of
August 5, 2008.
Exchangeable Debentures
During the first six months of 2008, certain holders of exchangeable debentures exercised
their option to exchange their debentures for shares of Chevron Corporation (Chevron) common
stock that Devon owns prior to the debentures August 15, 2008 maturity date. In lieu of delivering
Chevron common stock to an exchanging debenture holder, Devon may, at its option, pay to such
holder an amount of cash equal to the market value of Chevron common stock. During the first half
of 2008, Devon elected to pay the exchanging debenture holders cash totaling $47 million in lieu of
delivering shares of Chevron common stock. As a result of these exchanges, Devon retired
outstanding exchangeable debentures with a book value totaling $28 million and reduced the related
embedded derivative options balance by $19 million.
As of June 30, 2008, Devon has classified the exchangeable debentures as short-term borrowings
in the accompanying consolidated balance sheet. Although the exchangeable debentures have been due
within one year since August 15, 2007, Devon previously classified the debt as long-term
borrowings. The long-term classification was based on the uncertain timing of the closings of sales
of assets in West Africa, particularly the sale of assets in Equatorial Guinea. Based on the sale
proceeds received during the second quarter of 2008, Devon now intends to repay the exchangeable
debentures with cash on hand or short-term commercial paper borrowings.
5. Fair Value Measurements
Certain of Devons assets and liabilities are reported at fair value in the accompanying
balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial
instruments. The following tables provide fair value measurement information for such assets and
liabilities as of June 30, 2008 and December 31, 2007. Following the tables, additional information
is provided for those assets and liabilities in which Devon uses significant unobservable inputs
(Level 3) to measure fair value.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2008 |
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
|
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
|
|
|
|
|
|
Prices in |
|
Other |
|
Significant |
|
|
|
|
|
|
|
|
|
|
Active |
|
Observable |
|
Unobservable |
|
|
Carrying |
|
Total Fair |
|
Markets |
|
Inputs |
|
Inputs |
|
|
Amount |
|
Value |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
|
(In millions) |
Financial Assets (Liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term and long-term investments |
|
$ |
127 |
|
|
$ |
127 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
126 |
|
Investment in Chevron common stock |
|
$ |
1,406 |
|
|
$ |
1,406 |
|
|
$ |
1,406 |
|
|
$ |
|
|
|
$ |
|
|
Net oil and gas price swaps and collars |
|
$ |
(1,680 |
) |
|
$ |
(1,680 |
) |
|
$ |
|
|
|
$ |
(1,680 |
) |
|
$ |
|
|
Embedded option in exchangeable debentures |
|
$ |
(528 |
) |
|
$ |
(528 |
) |
|
$ |
|
|
|
$ |
(528 |
) |
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,493 |
) |
|
$ |
(1,493 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,493 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
|
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
|
|
|
|
|
|
Prices in |
|
Other |
|
Significant |
|
|
|
|
|
|
|
|
|
|
Active |
|
Observable |
|
Unobservable |
|
|
Carrying |
|
Total Fair |
|
Markets |
|
Inputs |
|
Inputs |
|
|
Amount |
|
Value |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
|
(In millions) |
Financial Assets (Liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
372 |
|
|
$ |
372 |
|
|
$ |
372 |
|
|
$ |
|
|
|
$ |
|
|
Investment in Chevron common stock |
|
$ |
1,324 |
|
|
$ |
1,324 |
|
|
$ |
1,324 |
|
|
$ |
|
|
|
$ |
|
|
Gas price swaps |
|
$ |
12 |
|
|
$ |
12 |
|
|
$ |
|
|
|
$ |
12 |
|
|
$ |
|
|
Embedded option in exchangeable debentures |
|
$ |
(488 |
) |
|
$ |
(488 |
) |
|
$ |
|
|
|
$ |
(488 |
) |
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,318 |
) |
|
$ |
(1,318 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,318 |
) |
Level 3 Fair Value Measurements
Short-term and long-term investments Devons short-term and long-term investments presented
in the tables above as of June 30, 2008 and December 31, 2007 consisted entirely of auction rate
securities, which are discussed in greater detail in Note 1. As of December 31, 2007, Devon
estimated the fair values of its short-term investments using quoted market prices. However, due to
the auction failures discussed in Note 1 and the lack of an active market for Devons long-term
auction rate securities, quoted market prices for the vast majority of these securities were not
available as of June 30, 2008. Therefore, Devon used valuation techniques that rely on
unobservable, or Level 3, inputs to estimate the fair values of its long-term auction rate
securities as of June 30, 2008. These inputs were based on the AAA credit rating of the securities,
the probability of full repayment of the securities considering the United States government
guarantees of substantially all of the underlying student loans and the collection of all accrued
interest to date. As a result of using these inputs, Devon concluded the estimated fair values of
its long-term auction rate securities approximated the par values as of June 30, 2008. At this
time, Devon does not believe the values of its long-term securities are impaired. Included below is
a summary of the changes in Devons Level 3 short-term and long-term investments during the first
half of 2008 (in millions).
|
|
|
|
|
Beginning balance |
|
$ |
|
|
Transfers from Level 1 to Level 3 |
|
|
129 |
|
Redemptions of principal |
|
|
(3 |
) |
|
|
|
|
Ending balance |
|
$ |
126 |
|
|
|
|
|
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Asset retirement obligation The fair values of the asset retirement obligations are
estimated using internal discounted cash flow calculations based upon Devons estimates of future
retirement costs. A summary of the changes in Devons asset retirement obligation, including
revisions of the estimated fair value in 2008 and 2007, is presented in Note 2.
6. Retirement Plans
Net Periodic Benefit Cost and Other Comprehensive Income
The following table presents the components of net periodic benefit cost and other
comprehensive income for Devons pension and other post retirement benefit plans for the
three-month and six-month periods ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
10 |
|
|
$ |
7 |
|
|
$ |
20 |
|
|
$ |
15 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
14 |
|
|
|
11 |
|
|
|
28 |
|
|
|
22 |
|
|
|
2 |
|
|
|
1 |
|
|
|
4 |
|
|
|
2 |
|
Expected return on plan assets |
|
|
(13 |
) |
|
|
(13 |
) |
|
|
(26 |
) |
|
|
(25 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss |
|
|
4 |
|
|
|
4 |
|
|
|
8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
|
15 |
|
|
|
9 |
|
|
|
30 |
|
|
|
20 |
|
|
|
2 |
|
|
|
1 |
|
|
|
4 |
|
|
|
2 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial
loss in net periodic benefit cost |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
(8 |
) |
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized |
|
$ |
11 |
|
|
$ |
5 |
|
|
$ |
22 |
|
|
$ |
12 |
|
|
$ |
2 |
|
|
$ |
1 |
|
|
$ |
4 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon previously disclosed in its financial statements for the year ended December 31, 2007,
that it expected to contribute $8 million to the Qualified and Supplemental Plans in 2008 and $6
million to the Postretirement Plans in 2008. Devon presently anticipates contributing an
additional $10 million to the Qualified and Supplemental Plans in 2008 for a total of $18 million.
As of June 30, 2008, Devon has contributed $13 million to the Qualified and Supplemental Plans and
$2 million to the Postretirement Plans.
7. Stockholders Equity
Preferred Stock Redemption
On June 20, 2008, Devon redeemed all 1.5 million outstanding shares of its 6.49% Series A
cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption
price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Stock Repurchases
During the first six months of 2008, Devon repurchased 2.8 million shares for $302 million, or
$106.01 per share, under programs approved by its Board of Directors. The 2.8 million shares
include 2.0 million shares that were repurchased under Devons 50 million share program and 0.8
million shares that were repurchased under Devons ongoing, annual stock repurchase program.
Dividends
Devon paid common stock dividends of $141 million (or a quarterly rate of $0.16 per share) and
$124 million (or a quarterly rate of $0.14 per share) in the first six months of 2008 and 2007,
respectively. During the first half of 2008 and 2007, Devon also paid $5 million in dividends to
preferred stockholders.
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
8. 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 gas producers and related parties, including Devon, have been named in various
lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers
and related parties used below-market prices, improper deductions, improper measurement techniques
and transactions with affiliates, which resulted in underpayment of royalties in connection with
natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. The
principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc.
et al. (the Wright case). The suit was originally filed in August 1996 in the United States
District Court for the Eastern District of Texas, but was consolidated in October 2000 with other
suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On
July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of
Texas to resume proceedings. On April 12, 2007, the court entered a trial plan and scheduling order
in which the case will proceed in phases. Two phases have been scheduled to date, with the first
scheduled to begin in August 2008 and the second scheduled to begin in February 2009. Devon is not
included in the groups of defendants selected for these first two phases. Devon believes that it
has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has
paid royalties in good faith. Devon does not currently believe that it is subject to material
exposure with respect to this lawsuit and, therefore, no liability related to this lawsuit has been
recorded.
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of
this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief
from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain
years by the Minerals Management Service (the MMS) have contained price thresholds, such that if
the market prices for oil or natural gas exceeded the thresholds for a given year, royalty relief
would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price
thresholds. In 2006, the MMS informed Devon and other oil and gas companies that the omission of
price thresholds from these leases was an error on its part and was not its intention. Accordingly,
the MMS invited Devon and the other affected oil and gas producers to renegotiate the terms and
conditions of the 1998 and 1999 leases to add price threshold provisions to the lease agreements
for periods after October 1, 2006. Devon has not renegotiated any of its existing leases.
The U.S. House of Representatives in January 2007 passed legislation that would have required
companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases.
This legislation was not passed by the U.S. Senate. However, Congress may consider similar
legislation in the future. Although Devon has not signed renegotiated leases, it has accrued
through June 30, 2008, approximately $40 million for royalties that would be due if price
thresholds were added to its 1998 and 1999 leases effective October 1, 2006.
Additionally, Devon has $35 million accrued at June 30, 2008 for royalties related to leases
issued under the Deep Water Royalty Relief Act in years other than 1998 or 1999. The leases issued
in these other years did include price thresholds, but in October 2007 a federal district court
ruled in favor of a plaintiff who had challenged the legality of including price thresholds in
these leases. This judgment is subject to appeal, and Devon will continue to accrue for royalties
on these leases until the matter is resolved.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation
activities associated with past operations, such as the Comprehensive Environmental Response,
Compensation, and Liability Act (CERCLA) and similar state statutes. In response to liabilities
associated with these activities, accruals have been established when reasonable estimates are
possible. Such accruals primarily include estimated costs associated with remediation. Devon has
not used discounting in determining its accrued liabilities for environmental remediation, and no
material claims for possible recovery from third party insurers or other parties related to
environmental costs have been recognized in
Devons consolidated financial statements. Devon adjusts the accruals when new remediation
responsibilities are discovered and probable costs become estimable, or when current remediation
estimates must be adjusted to reflect new information.
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Certain of Devons subsidiaries are involved in matters in which it has been alleged that such
subsidiaries are potentially responsible parties (PRPs) under CERCLA or similar state legislation
with respect to various waste disposal areas owned or operated by third parties. As of June 30,
2008, Devons balance sheet included $2 million of accrued liabilities, reflected in other
long-term liabilities, related to these and other environmental remediation liabilities. Devon does
not currently believe there is a reasonable possibility of incurring additional material costs in
excess of the current accruals recognized for such environmental remediation activities. With
respect to the sites in which Devon subsidiaries are PRPs, Devons conclusion is based in large
part on (i) Devons participation in consent decrees with both other PRPs and the Environmental
Protection Agency, which provide for performing the scope of work required for remediation and
contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de
minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devons
monetary exposure is not expected to be material.
Hurricane Contingencies
Historically, Devon maintained a comprehensive insurance program that included coverage for
physical damage to its offshore facilities caused by hurricanes. Devons historical insurance
program also included substantial business interruption coverage, which Devon is utilizing
to recover costs associated with the suspended production related to hurricanes that struck the
Gulf of Mexico in the third quarter of 2005. Under the terms of this insurance program, Devon was
entitled to be reimbursed for the portion of production suspended longer than forty-five days,
subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a
standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate
annual deductible.
Based on current estimates of physical damage and the anticipated length of time Devon will
have had production suspended, Devon expects its policy recoveries will exceed repair costs and
deductible amounts. This expectation is based upon several variables, including the $467 million
received in 2006 as a full settlement of the amount due from Devons primary insurers and $13
million received in 2007 as a full settlement of the amount due from certain of Devons secondary
insurers. As of June 30, 2008, $388 million of these proceeds had been utilized as reimbursement of
past repair costs and deductible amounts. The remaining proceeds of $92 million are expected to be
utilized as reimbursement of Devons anticipated future repair costs. Devon continues to negotiate
with its other secondary insurers and expects to receive additional policy recoveries as a result
of such negotiations.
Should Devons total policy recoveries, including the partial settlements already received
from Devons primary and secondary insurers, exceed all repair costs and deductible amounts, such
excess will be recognized as other income in the statement of operations in the period in which
such determination can be made.
The policy underlying the insurance program terms described above expired on August 31, 2006.
Devons current insurance program includes business interruption and physical damage coverage for
its business. However, due to significant changes in the insurance marketplace, Devon no longer has
coverage for damage that may be caused by named windstorms in the Gulf of Mexico.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business.
However, to Devons knowledge as of the date of this report, there were no other material pending
legal proceedings to which Devon is a party or to which any of its property is subject.
9. Share-Based Compensation
With the approval of Devons Compensation Committee, Devon modified the share-based
compensation arrangements for certain members of senior management (executives) in the second
quarter of 2008. The modified compensation arrangements provide that executives who meet certain
years-of-service and age criteria can retire and continue vesting in outstanding share-based
grants. As a condition to receiving the benefits of these modifications, the executives must agree
not to use or disclose Devons confidential information and not to solicit Devons employees and
customers. The
executives are required to agree to these conditions at retirement and again in each
subsequent year until all grants have vested.
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
This modification results in accelerated expense recognition as executives approach the
years-of-service and age criteria. Additionally, when the modification was made in the second
quarter of 2008, certain executives had already met the years-of-service and age criteria. As a
result, Devon recognized an additional $27 million of share-based compensation expense in the
second quarter of 2008 related to this modification. This additional expense would have been
recognized in future reporting periods if the modification had not been made and the executives
continued their employment at Devon.
10. Change in Fair Value of Non-Oil and Gas Financial Instruments
The components of the change in fair value of non-oil and gas financial instruments include
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Losses (gains) from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron common stock |
|
$ |
(195 |
) |
|
$ |
(146 |
) |
|
$ |
(82 |
) |
|
$ |
(152 |
) |
Option embedded in exchangeable debentures |
|
|
155 |
|
|
|
136 |
|
|
|
58 |
|
|
|
144 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(40 |
) |
|
$ |
(10 |
) |
|
$ |
(24 |
) |
|
$ |
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
11. Income Taxes
In the second quarter of 2008, Devon repatriated $1.3 billion in earnings from certain foreign
subsidiaries to the United States. Devon also expects to repatriate approximately $1.5 billion in
earnings from certain foreign subsidiaries to the United States during the last six months of 2008.
Subsequent to these repatriations, Devon does not expect to repatriate similar earnings from its
historical operations in the foreseeable future. Also in the second quarter of 2008, Devon made
certain tax policy election changes to minimize the taxes Devon otherwise would pay to all relevant
tax jurisdictions for the cash repatriations, as well as the taxable gains associated with the
sales of assets in West Africa. As a result of the repatriation and tax policy election changes,
Devon recognized additional tax expense of $312 million during the second quarter of 2008. Of the
$312 million, $295 million was recognized as current income tax expense, and $17 million was
recognized as deferred tax expense. Included in the $312 million additional tax expense is $183
million for tax positions in which the resulting tax benefits are not recognized in the
accompanying consolidated financial statements. If recognized, all of these unrecognized tax
benefits would affect Devons effective income tax rate.
12. Discontinued Operations
Divestiture Activity
In November 2006 and January 2007, Devon announced its plans to divest its operations in Egypt
and West Africa, including Equatorial Guinea, Gabon, Cote DIvoire and other countries in the
region. Pursuant to accounting rules for discontinued operations, Devon has classified all amounts
related to its operations in Egypt and West Africa as discontinued operations.
In the second quarter of 2008, Devon sold its assets and terminated its operations in certain
West African countries, consisting primarily of Equatorial Guinea and Gabon. As a result of the
sales, Devon recognized gains totaling $736 million ($647 million after taxes) in the second
quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price
adjustments).
In the fourth quarter of 2007, Devon sold its assets and terminated its operations in Egypt
and recognized a $90 million after-tax gain from proceeds of $341 million.
Devon has entered into agreements to sell its operations in Cote DIvoire and other countries
located in West Africa for approximately $250 million. Devon is obtaining the necessary partner and
government approvals for these properties
and expects to complete the remaining sales during the third quarter of 2008. Had these
transactions closed on June 30, 2008, Devon would have recognized after-tax gains of approximately
$100 million. The gains ultimately recorded when the transactions close will depend on
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
the carrying values of Devons assets and liabilities at the closing dates, as well as the effect
of any purchase price adjustments between the effective dates and the actual closing dates of the
sales.
Financial Statement Information
Revenues related to Devons discontinued operations totaled $127 million and $215 million in
the three months ended June 30, 2008 and June 30, 2007 and $332 million and $390 million in the six
months ended June 30, 2008 and 2007, respectively. These amounts do not include the divestiture
gains discussed in the previous section.
The following table presents the main classes of assets and liabilities associated with
Devons discontinued operations as of June 30, 2008 and December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
June 30, 2008 |
|
|
December 31, 2007 |
|
|
|
(In millions) |
|
Assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
8 |
|
|
$ |
9 |
|
Accounts receivable |
|
|
5 |
|
|
|
83 |
|
Deferred tax asset |
|
|
68 |
|
|
|
|
|
Other current assets |
|
|
24 |
|
|
|
28 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
105 |
|
|
$ |
120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term assets property and equipment, net of
accumulated depreciation, depletion and amortization |
|
$ |
84 |
|
|
$ |
1,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable trade |
|
$ |
2 |
|
|
$ |
23 |
|
Revenues and royalties due to others |
|
|
2 |
|
|
|
11 |
|
Income taxes payable |
|
|
6 |
|
|
|
100 |
|
Current portion of asset retirement obligation |
|
|
|
|
|
|
9 |
|
Accrued expenses and other current liabilities |
|
|
6 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
16 |
|
|
$ |
145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
5 |
|
|
$ |
35 |
|
Deferred income taxes |
|
|
19 |
|
|
|
366 |
|
Other long-term liabilities |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
24 |
|
|
$ |
404 |
|
|
|
|
|
|
|
|
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. 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 for the three-month
and six-month periods ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
|
|
|
|
|
|
|
|
Earnings |
|
|
Weighted |
|
|
|
|
|
|
Applicable to |
|
|
Average |
|
|
Net |
|
|
|
Common |
|
|
Common Shares |
|
|
Earnings |
|
|
|
Stockholders |
|
|
Outstanding |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
594 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
591 |
|
|
|
446 |
|
|
$ |
1.33 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
591 |
|
|
|
450 |
|
|
$ |
1.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
824 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
821 |
|
|
|
446 |
|
|
$ |
1.84 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
821 |
|
|
|
450 |
|
|
$ |
1.82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,245 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
1,240 |
|
|
|
445 |
|
|
$ |
2.79 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
1,240 |
|
|
|
450 |
|
|
$ |
2.76 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,398 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
1,393 |
|
|
|
445 |
|
|
$ |
3.13 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
1,393 |
|
|
|
450 |
|
|
$ |
3.09 |
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. During the three-month and six-month periods
ended June 30, 2008, no shares and 1.5 million shares, respectively, were excluded from the diluted
earnings per share calculations. During the three-month and six-month periods ended June 30, 2007,
4.0 million shares and 4.1 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)
14. Segment Information
Following is certain financial information regarding Devons reporting segments. The revenues
reported are all from external customers.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
As of June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
3,110 |
|
|
$ |
1,622 |
|
|
$ |
701 |
|
|
$ |
5,433 |
|
Property and equipment, net of accumulated
depreciation, depletion and amortization |
|
|
19,976 |
|
|
|
8,857 |
|
|
|
1,351 |
|
|
|
30,184 |
|
Goodwill |
|
|
3,050 |
|
|
|
2,963 |
|
|
|
68 |
|
|
|
6,081 |
|
Other long-term assets |
|
|
1,726 |
|
|
|
61 |
|
|
|
295 |
|
|
|
2,082 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
27,862 |
|
|
$ |
13,503 |
|
|
$ |
2,415 |
|
|
$ |
43,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
4,994 |
|
|
$ |
582 |
|
|
$ |
456 |
|
|
$ |
6,032 |
|
Long-term debt |
|
|
1,852 |
|
|
|
2,977 |
|
|
|
|
|
|
|
4,829 |
|
Asset retirement obligation, long-term |
|
|
689 |
|
|
|
646 |
|
|
|
95 |
|
|
|
1,430 |
|
Other long-term liabilities |
|
|
938 |
|
|
|
46 |
|
|
|
28 |
|
|
|
1,012 |
|
Deferred income taxes |
|
|
4,871 |
|
|
|
2,086 |
|
|
|
87 |
|
|
|
7,044 |
|
Stockholders equity |
|
|
14,518 |
|
|
|
7,166 |
|
|
|
1,749 |
|
|
|
23,433 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
27,862 |
|
|
$ |
13,503 |
|
|
$ |
2,415 |
|
|
$ |
43,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
566 |
|
|
$ |
498 |
|
|
$ |
391 |
|
|
$ |
1,455 |
|
Gas sales |
|
|
1,688 |
|
|
|
517 |
|
|
|
5 |
|
|
|
2,210 |
|
NGL sales |
|
|
305 |
|
|
|
74 |
|
|
|
|
|
|
|
379 |
|
Net loss on oil and gas derivative financial instruments |
|
|
(1,215 |
) |
|
|
|
|
|
|
|
|
|
|
(1,215 |
) |
Marketing and midstream revenues |
|
|
707 |
|
|
|
12 |
|
|
|
|
|
|
|
719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
2,051 |
|
|
|
1,101 |
|
|
|
396 |
|
|
|
3,548 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
279 |
|
|
|
211 |
|
|
|
47 |
|
|
|
537 |
|
Production taxes |
|
|
104 |
|
|
|
1 |
|
|
|
71 |
|
|
|
176 |
|
Marketing and midstream operating costs and expenses |
|
|
510 |
|
|
|
5 |
|
|
|
|
|
|
|
515 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
481 |
|
|
|
227 |
|
|
|
54 |
|
|
|
762 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
54 |
|
|
|
7 |
|
|
|
1 |
|
|
|
62 |
|
Accretion of asset retirement obligation |
|
|
10 |
|
|
|
10 |
|
|
|
2 |
|
|
|
22 |
|
General and administrative expenses |
|
|
145 |
|
|
|
34 |
|
|
|
1 |
|
|
|
180 |
|
Interest expense |
|
|
36 |
|
|
|
54 |
|
|
|
|
|
|
|
90 |
|
Change in fair value of non-oil and gas derivative financial
instruments |
|
|
(40 |
) |
|
|
|
|
|
|
|
|
|
|
(40 |
) |
Other income, net |
|
|
(11 |
) |
|
|
|
|
|
|
(6 |
) |
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,568 |
|
|
|
549 |
|
|
|
170 |
|
|
|
2,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax expense |
|
|
483 |
|
|
|
552 |
|
|
|
226 |
|
|
|
1,261 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
299 |
|
|
|
46 |
|
|
|
69 |
|
|
|
414 |
|
Deferred |
|
|
163 |
|
|
|
104 |
|
|
|
(14 |
) |
|
|
253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
462 |
|
|
|
150 |
|
|
|
55 |
|
|
|
667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
21 |
|
|
|
402 |
|
|
|
171 |
|
|
|
594 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
851 |
|
|
|
851 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
144 |
|
|
|
144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
707 |
|
|
|
707 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
21 |
|
|
|
402 |
|
|
|
878 |
|
|
|
1,301 |
|
Preferred stock dividends |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
18 |
|
|
$ |
402 |
|
|
$ |
878 |
|
|
$ |
1,298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
1,654 |
|
|
$ |
182 |
|
|
$ |
150 |
|
|
$ |
1,986 |
|
Revision of future ARO |
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,654 |
|
|
$ |
182 |
|
|
$ |
172 |
|
|
$ |
2,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
305 |
|
|
$ |
185 |
|
|
$ |
375 |
|
|
$ |
865 |
|
Gas sales |
|
|
983 |
|
|
|
380 |
|
|
|
3 |
|
|
|
1,366 |
|
NGL sales |
|
|
177 |
|
|
|
47 |
|
|
|
|
|
|
|
224 |
|
Net gain on oil and gas derivative financial instruments |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
14 |
|
Marketing and midstream revenues |
|
|
452 |
|
|
|
8 |
|
|
|
|
|
|
|
460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,931 |
|
|
|
620 |
|
|
|
378 |
|
|
|
2,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
256 |
|
|
|
140 |
|
|
|
43 |
|
|
|
439 |
|
Production taxes |
|
|
59 |
|
|
|
1 |
|
|
|
30 |
|
|
|
90 |
|
Marketing and midstream operating costs and expenses |
|
|
338 |
|
|
|
3 |
|
|
|
|
|
|
|
341 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
402 |
|
|
|
182 |
|
|
|
61 |
|
|
|
645 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
44 |
|
|
|
5 |
|
|
|
|
|
|
|
49 |
|
Accretion of asset retirement obligation |
|
|
9 |
|
|
|
8 |
|
|
|
1 |
|
|
|
18 |
|
General and administrative expenses |
|
|
91 |
|
|
|
27 |
|
|
|
(5 |
) |
|
|
113 |
|
Interest expense |
|
|
57 |
|
|
|
50 |
|
|
|
|
|
|
|
107 |
|
Change in fair value of non-oil and gas derivative financial
instruments |
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
Other income, net |
|
|
(6 |
) |
|
|
(2 |
) |
|
|
(9 |
) |
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,240 |
|
|
|
414 |
|
|
|
121 |
|
|
|
1,775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax expense |
|
|
691 |
|
|
|
206 |
|
|
|
257 |
|
|
|
1,154 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
55 |
|
|
|
43 |
|
|
|
76 |
|
|
|
174 |
|
Deferred |
|
|
166 |
|
|
|
(4 |
) |
|
|
(6 |
) |
|
|
156 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
221 |
|
|
|
39 |
|
|
|
70 |
|
|
|
330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
470 |
|
|
|
167 |
|
|
|
187 |
|
|
|
824 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
128 |
|
|
|
128 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
48 |
|
|
|
48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
80 |
|
|
|
80 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
470 |
|
|
|
167 |
|
|
|
267 |
|
|
|
904 |
|
Preferred stock dividends |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
467 |
|
|
$ |
167 |
|
|
$ |
267 |
|
|
$ |
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,079 |
|
|
$ |
192 |
|
|
$ |
109 |
|
|
$ |
1,380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Six Months Ended June 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
1,009 |
|
|
$ |
838 |
|
|
$ |
858 |
|
|
$ |
2,705 |
|
Gas sales |
|
|
2,924 |
|
|
|
906 |
|
|
|
10 |
|
|
|
3,840 |
|
NGL sales |
|
|
571 |
|
|
|
136 |
|
|
|
|
|
|
|
707 |
|
Net loss on oil and gas derivative financial instruments |
|
|
(2,003 |
) |
|
|
|
|
|
|
|
|
|
|
(2,003 |
) |
Marketing and midstream revenues |
|
|
1,249 |
|
|
|
25 |
|
|
|
|
|
|
|
1,274 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
3,750 |
|
|
|
1,905 |
|
|
|
868 |
|
|
|
6,523 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
545 |
|
|
|
405 |
|
|
|
93 |
|
|
|
1,043 |
|
Production taxes |
|
|
183 |
|
|
|
2 |
|
|
|
125 |
|
|
|
310 |
|
Marketing and midstream operating costs and expenses |
|
|
887 |
|
|
|
10 |
|
|
|
|
|
|
|
897 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
941 |
|
|
|
438 |
|
|
|
120 |
|
|
|
1,499 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
105 |
|
|
|
13 |
|
|
|
1 |
|
|
|
119 |
|
Accretion of asset retirement obligation |
|
|
21 |
|
|
|
20 |
|
|
|
3 |
|
|
|
44 |
|
General and administrative expenses |
|
|
259 |
|
|
|
68 |
|
|
|
1 |
|
|
|
328 |
|
Interest expense |
|
|
88 |
|
|
|
104 |
|
|
|
|
|
|
|
192 |
|
Change in fair value of non-oil and gas derivative financial
instruments |
|
|
(24 |
) |
|
|
|
|
|
|
|
|
|
|
(24 |
) |
Other income, net |
|
|
(17 |
) |
|
|
(5 |
) |
|
|
(16 |
) |
|
|
(38 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
2,988 |
|
|
|
1,055 |
|
|
|
327 |
|
|
|
4,370 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax expense |
|
|
762 |
|
|
|
850 |
|
|
|
541 |
|
|
|
2,153 |
|
Income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
345 |
|
|
|
64 |
|
|
|
108 |
|
|
|
517 |
|
Deferred |
|
|
213 |
|
|
|
152 |
|
|
|
26 |
|
|
|
391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
558 |
|
|
|
216 |
|
|
|
134 |
|
|
|
908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
204 |
|
|
|
634 |
|
|
|
407 |
|
|
|
1,245 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
1,040 |
|
|
|
1,040 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
235 |
|
|
|
235 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
805 |
|
|
|
805 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
204 |
|
|
|
634 |
|
|
|
1,212 |
|
|
|
2,050 |
|
Preferred stock dividends |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
199 |
|
|
$ |
634 |
|
|
$ |
1,212 |
|
|
$ |
2,045 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
2,965 |
|
|
$ |
698 |
|
|
$ |
301 |
|
|
$ |
3,964 |
|
Revision of future ARO |
|
|
70 |
|
|
|
73 |
|
|
|
19 |
|
|
|
162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
3,035 |
|
|
$ |
771 |
|
|
$ |
320 |
|
|
$ |
4,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Six Months Ended June 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
539 |
|
|
$ |
338 |
|
|
$ |
679 |
|
|
$ |
1,556 |
|
Gas sales |
|
|
1,872 |
|
|
|
736 |
|
|
|
4 |
|
|
|
2,612 |
|
NGL sales |
|
|
313 |
|
|
|
88 |
|
|
|
|
|
|
|
401 |
|
Net loss on oil and gas derivative financial instruments |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
(6 |
) |
Marketing and midstream revenues |
|
|
823 |
|
|
|
16 |
|
|
|
|
|
|
|
839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
3,541 |
|
|
|
1,178 |
|
|
|
683 |
|
|
|
5,402 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
504 |
|
|
|
283 |
|
|
|
82 |
|
|
|
869 |
|
Production taxes |
|
|
115 |
|
|
|
2 |
|
|
|
53 |
|
|
|
170 |
|
Marketing and midstream operating costs and expenses |
|
|
604 |
|
|
|
7 |
|
|
|
|
|
|
|
611 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
773 |
|
|
|
342 |
|
|
|
117 |
|
|
|
1,232 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
85 |
|
|
|
10 |
|
|
|
|
|
|
|
95 |
|
Accretion of asset retirement obligation |
|
|
19 |
|
|
|
15 |
|
|
|
2 |
|
|
|
36 |
|
General and administrative expenses |
|
|
183 |
|
|
|
52 |
|
|
|
(3 |
) |
|
|
232 |
|
Interest expense |
|
|
116 |
|
|
|
101 |
|
|
|
|
|
|
|
217 |
|
Change in fair value of non-oil and gas derivative financial
instruments |
|
|
(8 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(9 |
) |
Other income, net |
|
|
(18 |
) |
|
|
(5 |
) |
|
|
(20 |
) |
|
|
(43 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
2,373 |
|
|
|
806 |
|
|
|
231 |
|
|
|
3,410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax
expense |
|
|
1,168 |
|
|
|
372 |
|
|
|
452 |
|
|
|
1,992 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
122 |
|
|
|
105 |
|
|
|
136 |
|
|
|
363 |
|
Deferred |
|
|
252 |
|
|
|
(5 |
) |
|
|
(16 |
) |
|
|
231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
374 |
|
|
|
100 |
|
|
|
120 |
|
|
|
594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
794 |
|
|
|
272 |
|
|
|
332 |
|
|
|
1,398 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
265 |
|
|
|
265 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
108 |
|
|
|
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
157 |
|
|
|
157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
794 |
|
|
|
272 |
|
|
|
489 |
|
|
|
1,555 |
|
Preferred stock dividends |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
789 |
|
|
$ |
272 |
|
|
$ |
489 |
|
|
$ |
1,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
2,022 |
|
|
$ |
661 |
|
|
$ |
215 |
|
|
$ |
2,898 |
|
Revision of future ARO |
|
|
210 |
|
|
|
99 |
|
|
|
2 |
|
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
2,232 |
|
|
$ |
760 |
|
|
$ |
217 |
|
|
$ |
3,209 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion addresses material changes in our results of operations and capital
resources and uses for the three-month and six-month periods ended June 30, 2008, compared to the
three-month and six-month periods ended June 30, 2007, and in our financial condition and liquidity
since December 31, 2007. It is presumed that readers have read or have access to our 2007 Annual
Report on Form 10-K/A, which includes disclosures regarding critical accounting policies and
estimates as part of Managements Discussion and Analysis of Financial Condition and Results of
Operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
Overview
During the second quarter and first six months of 2008, we generated net earnings of $1.3
billion and $2.1 billion, respectively, or $2.88 and $4.55 per diluted share, representing
increases of 44% and 32% over the same periods of 2007. Additionally, net cash provided by
operating activities for the first half of 2008 climbed to a record amount of $5.2 billion,
representing a 55% increase over 2007. These increases in earnings and cash flow are largely
attributable to the following factors:
|
|
|
Production increased 4% and 7% in the second quarter and first six months of 2008,
respectively. |
|
|
|
|
The combined realized price without hedges for oil, gas and NGLs increased 58% and 48%
in the second quarter and first six months of 2008, respectively. |
|
|
|
|
Oil and gas hedges generated net losses of $1.2 billion and $2.0 billion in the second
quarter and first six months of 2008, respectively. Included in these amounts are cash
payments of $303 million and $311 million, respectively. |
|
|
|
|
Marketing and midstream operating profit increased 71% and 65% in the second quarter and
first six months of 2008, respectively. |
|
|
|
|
Per unit operating costs rose 18% and 12% in the second quarter and first six months of
2008, respectively. |
|
|
|
|
General and administrative expenses increased 59% and 41% in the second quarter and
first six months of 2008, respectively. |
|
|
|
|
The effective income tax rates for the second quarter and first six months of 2008 were
53% and 42%, respectively. |
|
|
|
|
Cash spent on capital expenditures for oil and gas exploration and development
activities were $3.6 billion during the first half of 2008. |
Additionally, we made significant progress toward completion of our African divestiture
program during the second quarter of 2008. We completed the sales of assets in certain West African
countries, including Equatorial Guineathe largest individual transaction in the divestiture
program. As a result of the sales, we recognized after-tax gains totaling $647 million in the
second quarter of 2008 from proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase
price adjustments). Also, in conjunction with these asset sales, we repatriated an additional $1.3
billion of earnings from certain foreign subsidiaries to the United States in the second quarter of
2008. We also expect to repatriate $1.5 billion from certain foreign subsidiaries to the United
States in the second half of 2008.
With the proceeds from asset sales, repatriated funds and growing cash flow from operations,
we repaid $2.5 billion of commercial paper and credit facility borrowings during the first six
months of 2008. We also repurchased 2.8 million common shares for $302 million during the first six
months of 2008.
Results of Operations
Revenues
Oil, Gas and NGL Sales
The three-month and six-month comparison of our oil, gas and NGL production and the related
prices realized without the effect of hedges is shown in the following tables. The amounts for all
periods presented exclude our Egyptian operations that were sold in the fourth quarter of 2007 and
our West African operations, which are classified as discontinued operations in our financial
statements.
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
13 |
|
|
|
15 |
|
|
|
-9 |
% |
|
|
27 |
|
|
|
28 |
|
|
|
-1 |
% |
Gas (Bcf) |
|
|
230 |
|
|
|
212 |
|
|
|
+8 |
% |
|
|
453 |
|
|
|
414 |
|
|
|
+9 |
% |
NGLs (MMBbls) |
|
|
7 |
|
|
|
6 |
|
|
|
+9 |
% |
|
|
14 |
|
|
|
12 |
|
|
|
+12 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
59 |
|
|
|
56 |
|
|
|
+4 |
% |
|
|
117 |
|
|
|
109 |
|
|
|
+7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
110.56 |
|
|
$ |
60.01 |
|
|
|
+84 |
% |
|
$ |
98.98 |
|
|
$ |
56.22 |
|
|
|
+76 |
% |
Gas (Per Mcf) |
|
$ |
9.61 |
|
|
$ |
6.43 |
|
|
|
+49 |
% |
|
$ |
8.48 |
|
|
$ |
6.31 |
|
|
|
+34 |
% |
NGLs (Per Bbl) |
|
$ |
54.08 |
|
|
$ |
35.03 |
|
|
|
+54 |
% |
|
$ |
50.76 |
|
|
$ |
32.26 |
|
|
|
+57 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
69.14 |
|
|
$ |
43.68 |
|
|
|
+58 |
% |
|
$ |
62.12 |
|
|
$ |
41.87 |
|
|
|
+48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
1,455 |
|
|
$ |
865 |
|
|
|
+68 |
% |
|
$ |
2,705 |
|
|
$ |
1,556 |
|
|
|
+74 |
% |
Gas sales |
|
|
2,210 |
|
|
|
1,366 |
|
|
|
+62 |
% |
|
|
3,840 |
|
|
|
2,612 |
|
|
|
+47 |
% |
NGL sales |
|
|
379 |
|
|
|
224 |
|
|
|
+69 |
% |
|
|
707 |
|
|
|
401 |
|
|
|
+76 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
4,044 |
|
|
$ |
2,455 |
|
|
|
+65 |
% |
|
$ |
7,252 |
|
|
$ |
4,569 |
|
|
|
+59 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic |
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
5 |
|
|
|
5 |
|
|
|
-5 |
% |
|
|
9 |
|
|
|
9 |
|
|
|
-1 |
% |
Gas (Bcf) |
|
|
176 |
|
|
|
155 |
|
|
|
+14 |
% |
|
|
347 |
|
|
|
301 |
|
|
|
+15 |
% |
NGLs (MMBbls) |
|
|
6 |
|
|
|
5 |
|
|
|
+13 |
% |
|
|
12 |
|
|
|
10 |
|
|
|
+17 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
40 |
|
|
|
36 |
|
|
|
+11 |
% |
|
|
79 |
|
|
|
70 |
|
|
|
+13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
122.47 |
|
|
$ |
62.68 |
|
|
|
+95 |
% |
|
$ |
109.08 |
|
|
$ |
57.67 |
|
|
|
+89 |
% |
Gas (Per Mcf) |
|
$ |
9.56 |
|
|
$ |
6.35 |
|
|
|
+51 |
% |
|
$ |
8.42 |
|
|
$ |
6.22 |
|
|
|
+35 |
% |
NGLs (Per Bbl) |
|
$ |
50.66 |
|
|
$ |
33.26 |
|
|
|
+52 |
% |
|
$ |
47.78 |
|
|
$ |
30.54 |
|
|
|
+56 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
63.88 |
|
|
$ |
40.71 |
|
|
|
+57 |
% |
|
$ |
56.95 |
|
|
$ |
39.05 |
|
|
|
+46 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
566 |
|
|
$ |
305 |
|
|
|
+86 |
% |
|
$ |
1,009 |
|
|
$ |
539 |
|
|
|
+87 |
% |
Gas sales |
|
|
1,688 |
|
|
|
983 |
|
|
|
+72 |
% |
|
|
2,924 |
|
|
|
1,872 |
|
|
|
+56 |
% |
NGL sales |
|
|
305 |
|
|
|
177 |
|
|
|
+72 |
% |
|
|
571 |
|
|
|
313 |
|
|
|
+83 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
2,559 |
|
|
$ |
1,465 |
|
|
|
+75 |
% |
|
$ |
4,504 |
|
|
$ |
2,724 |
|
|
|
+65 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
5 |
|
|
|
4 |
|
|
|
+32 |
% |
|
|
10 |
|
|
|
8 |
|
|
|
+32 |
% |
Gas (Bcf) |
|
|
53 |
|
|
|
56 |
|
|
|
-7 |
% |
|
|
105 |
|
|
|
112 |
|
|
|
-7 |
% |
NGLs (MMBbls) |
|
|
1 |
|
|
|
1 |
|
|
|
-8 |
% |
|
|
2 |
|
|
|
2 |
|
|
|
-10 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
16 |
|
|
|
14 |
|
|
|
+4 |
% |
|
|
30 |
|
|
|
28 |
|
|
|
+3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
94.35 |
|
|
$ |
46.32 |
|
|
|
+104 |
% |
|
$ |
84.16 |
|
|
$ |
45.01 |
|
|
|
+87 |
% |
Gas (Per Mcf) |
|
$ |
9.76 |
|
|
$ |
6.66 |
|
|
|
+47 |
% |
|
$ |
8.66 |
|
|
$ |
6.55 |
|
|
|
+32 |
% |
NGLs (Per Bbl) |
|
$ |
75.10 |
|
|
$ |
43.82 |
|
|
|
+71 |
% |
|
$ |
68.86 |
|
|
$ |
40.37 |
|
|
|
+71 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
72.14 |
|
|
$ |
41.99 |
|
|
|
+72 |
% |
|
$ |
64.01 |
|
|
$ |
40.88 |
|
|
|
+57 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
498 |
|
|
$ |
185 |
|
|
|
+168 |
% |
|
$ |
838 |
|
|
$ |
338 |
|
|
|
+148 |
% |
Gas sales |
|
|
517 |
|
|
|
380 |
|
|
|
+36 |
% |
|
|
906 |
|
|
|
736 |
|
|
|
+23 |
% |
NGL sales |
|
|
74 |
|
|
|
47 |
|
|
|
+57 |
% |
|
|
136 |
|
|
|
88 |
|
|
|
+54 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
1,089 |
|
|
$ |
612 |
|
|
|
+78 |
% |
|
$ |
1,880 |
|
|
$ |
1,162 |
|
|
|
+62 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
3 |
|
|
|
6 |
|
|
|
-41 |
% |
|
|
8 |
|
|
|
11 |
|
|
|
-25 |
% |
Gas (Bcf) |
|
|
1 |
|
|
|
1 |
|
|
|
-14 |
% |
|
|
1 |
|
|
|
1 |
|
|
|
+27 |
% |
NGLs (MMBbls) |
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
N/M |
|
Oil, Gas and NGLs (MMBoe)(1) |
|
|
3 |
|
|
|
6 |
|
|
|
-41 |
% |
|
|
8 |
|
|
|
11 |
|
|
|
-24 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
119.87 |
|
|
$ |
67.57 |
|
|
|
+77 |
% |
|
$ |
105.63 |
|
|
$ |
62.76 |
|
|
|
+68 |
% |
Gas (Per Mcf) |
|
$ |
11.00 |
|
|
$ |
6.19 |
|
|
|
+78 |
% |
|
$ |
9.56 |
|
|
$ |
5.16 |
|
|
|
+85 |
% |
NGLs (Per Bbl) |
|
$ |
|
|
|
$ |
|
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
|
|
|
|
N/M |
|
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
118.70 |
|
|
$ |
67.11 |
|
|
|
+77 |
% |
|
$ |
104.68 |
|
|
$ |
62.39 |
|
|
|
+68 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
391 |
|
|
$ |
375 |
|
|
|
+4 |
% |
|
$ |
858 |
|
|
$ |
679 |
|
|
|
+26 |
% |
Gas sales |
|
|
5 |
|
|
|
3 |
|
|
|
+52 |
% |
|
|
10 |
|
|
|
4 |
|
|
|
+134 |
% |
NGL sales |
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
396 |
|
|
$ |
378 |
|
|
|
+5 |
% |
|
$ |
868 |
|
|
$ |
683 |
|
|
|
+27 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel
of oil, based upon the approximate relative energy content of natural gas and oil, which rate
is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are
converted to Boe on a one-to-one basis with oil. |
|
(2) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
|
N/M |
|
Not meaningful. |
29
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, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2007 sales |
|
$ |
865 |
|
|
$ |
1,366 |
|
|
$ |
224 |
|
|
$ |
2,455 |
|
Changes due to volumes |
|
|
(75 |
) |
|
|
113 |
|
|
|
21 |
|
|
|
59 |
|
Changes due to prices. |
|
|
665 |
|
|
|
731 |
|
|
|
134 |
|
|
|
1,530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales |
|
$ |
1,455 |
|
|
$ |
2,210 |
|
|
$ |
379 |
|
|
$ |
4,044 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2007 sales |
|
$ |
1,556 |
|
|
$ |
2,612 |
|
|
$ |
401 |
|
|
$ |
4,569 |
|
Changes due to volumes |
|
|
(20 |
) |
|
|
245 |
|
|
|
48 |
|
|
|
273 |
|
Changes due to prices. |
|
|
1,169 |
|
|
|
983 |
|
|
|
258 |
|
|
|
2,410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales |
|
$ |
2,705 |
|
|
$ |
3,840 |
|
|
$ |
707 |
|
|
$ |
7,252 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales decreased $75 million in the second quarter of 2008 due to a two million barrel, or
9%, decrease in production. International production decreased approximately three million barrels
due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. This was
partially offset by an additional one million barrels of production due to increased development
activity at our Jackfish and Lloydminster areas in Canada.
Oil sales increased $665 million in the second quarter of 2008 as a result of an 84% increase
in our realized price without hedges. The average NYMEX West Texas Intermediate index price
increased 91% during the same time period, accounting for the majority of the increase.
Oil sales increased $1.2 billion in the first half of 2008 as a result of a 76% increase in
our realized price without hedges. The average NYMEX West Texas Intermediate index price increased
80% during the same time period, accounting for the majority of the increase.
Gas Sales
An 18 Bcf, or 8%, increase in production during the second quarter of 2008 caused gas sales to
increase by $113 million. Our drilling and development program in the Barnett Shale field in north
Texas contributed 22 Bcf to the gas production increase. This increase and the effect of new
drilling and development in our other North American properties were partially offset by natural
production declines.
Gas sales increased $731 million during the second quarter of 2008 as a result of a 49%
increase in our realized price without hedges. This increase is largely due to increases in the
regional index prices upon which our gas sales are based.
A 39 Bcf, or 9%, increase in production during the first half of 2008 caused gas sales to
increase by $245 million. Our drilling and development program in the Barnett Shale field in north
Texas contributed 42 Bcf to the gas production increase. This increase and the effect of new
drilling and development in our other North American properties were partially offset by natural
production declines.
Gas sales increased $983 million during the first half of 2008 as a result of a 34% increase
in our realized price without hedges. This increase is largely due to increases in the regional
index prices upon which our gas sales are based.
30
Net (Loss) Gain on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated with our oil and gas hedges for
the second quarter and first half of 2008 and 2007. The first table presents the cash settlements
and unrealized losses and gains 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 for the
second quarter and first half of 2008 and 2007. The prices do not include the effects of unrealized
losses and gains.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
(153 |
) |
|
$ |
5 |
|
|
$ |
(161 |
) |
|
$ |
15 |
|
Gas price collars |
|
|
(150 |
) |
|
|
|
|
|
|
(150 |
) |
|
|
2 |
|
Oil price collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received |
|
|
(303 |
) |
|
|
5 |
|
|
|
(311 |
) |
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (losses) gains on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
(247 |
) |
|
|
9 |
|
|
|
(618 |
) |
|
|
(19 |
) |
Gas price collars |
|
|
(620 |
) |
|
|
|
|
|
|
(1,028 |
) |
|
|
(4 |
) |
Oil price collars |
|
|
(45 |
) |
|
|
|
|
|
|
(46 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized (losses) gains on fair value
changes |
|
|
(912 |
) |
|
|
9 |
|
|
|
(1,692 |
) |
|
|
(23 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) gain on oil and gas derivative financial
Instruments |
|
$ |
(1,215 |
) |
|
$ |
14 |
|
|
$ |
(2,003 |
) |
|
$ |
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2008 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
110.56 |
|
|
$ |
9.61 |
|
|
$ |
54.08 |
|
|
$ |
69.14 |
|
Cash settlements of hedges |
|
|
(0.01 |
) |
|
|
(1.32 |
) |
|
|
|
|
|
|
(5.18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
110.55 |
|
|
$ |
8.29 |
|
|
$ |
54.08 |
|
|
$ |
63.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2007 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
60.01 |
|
|
$ |
6.43 |
|
|
$ |
35.03 |
|
|
$ |
43.68 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.03 |
|
|
|
|
|
|
|
0.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
60.01 |
|
|
$ |
6.46 |
|
|
$ |
35.03 |
|
|
$ |
43.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2008 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
98.98 |
|
|
$ |
8.48 |
|
|
$ |
50.76 |
|
|
$ |
62.12 |
|
Cash settlements of hedges |
|
|
|
|
|
|
(0.69 |
) |
|
|
|
|
|
|
(2.67 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
98.98 |
|
|
$ |
7.79 |
|
|
$ |
50.76 |
|
|
$ |
59.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2007 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
56.22 |
|
|
$ |
6.31 |
|
|
$ |
32.26 |
|
|
$ |
41.87 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.04 |
|
|
|
|
|
|
|
0.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
56.22 |
|
|
$ |
6.35 |
|
|
$ |
32.26 |
|
|
$ |
42.03 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our oil and gas derivative financial instruments include price swaps and costless collars. For
the price swaps, we receive a fixed price for our production and pay a variable market price to the
contract counterparty. The costless 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, we cash-settle the difference with the counterparty to the
collars. Cash settlements as presented in the tables above represent realized losses or gains
related to our price swaps and collars.
31
During the second quarter and first half of 2008, we paid $303 million, or $1.32 per Mcf, and
$311 million, or $0.69 per Mcf, respectively, to counterparties to settle our gas price swaps and
collars. During the second quarter and first half of 2007, we received $5 million, or $0.03 per
Mcf, and $17 million, or $0.04 per Mcf, respectively, from counterparties to settle our gas price
swaps and collars.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes
in the fair values of our oil and gas derivative instruments in each reporting period. We estimate
the fair values of our oil and gas derivative financial instruments primarily by using internal
discounted cash flow calculations. From time to time, we validate our valuation techniques by
comparing our internally generated fair value estimates with those obtained from contract
counterparties and/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 price
swaps and collars at June 30, 2008, a 10% increase in these forward curves would have increased our
second quarter 2008 unrealized loss for our oil and gas derivative financial instruments by
approximately $550 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.
During the second quarter and first half of 2008, we recognized unrealized losses totaling
$912 million and $1.7 billion, respectively, related to our oil and gas derivative instruments.
These losses result primarily from a significant increase in the Inside FERC Henry Hub and the
NYMEX West Texas Intermediate forward curves subsequent to the trade dates for our oil and gas
price swaps and collars.
During the second quarter and first half of 2007, we recognized an unrealized gain totaling $9
million and an unrealized loss totaling $23 million, related to our gas derivative instruments.
Marketing and Midstream Revenues and Operating Costs and Expenses
The details of the changes in marketing and midstream revenues, operating costs and expenses
and the resulting operating profit between the three months ended June 30, 2008 and 2007 and the
six months ended June 30, 2008 and 2007 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Marketing and midstream ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
719 |
|
|
$ |
460 |
|
|
|
+56 |
% |
|
$ |
1,274 |
|
|
$ |
839 |
|
|
|
+52 |
% |
Operating costs and expenses |
|
|
515 |
|
|
|
341 |
|
|
|
+51 |
% |
|
|
897 |
|
|
|
611 |
|
|
|
+47 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
204 |
|
|
$ |
119 |
|
|
|
+71 |
% |
|
$ |
377 |
|
|
$ |
228 |
|
|
|
+65 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
Marketing and midstream revenues increased $259 million and operating costs and expenses also
increased $174 million, causing operating profit to increase $85 million during the second quarter
of 2008. Revenues and expenses increased primarily due to higher natural gas and NGL prices, as
well as higher gas pipeline throughput in the Barnett Shale.
Marketing and midstream revenues increased $435 million and operating costs and expenses also
increased $286 million, causing operating profit to increase $149 million during the first six
months of 2008. Revenues and expenses increased primarily due to higher natural gas and NGL prices,
as well as higher gas pipeline throughput in the Barnett Shale.
32
Oil, Gas and NGL Production and Operating Expenses
The three-month and six-month comparisons of oil, gas and NGL production and operating
expenses are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Production and operating expenses ($ in
millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
537 |
|
|
$ |
439 |
|
|
|
+22 |
% |
|
$ |
1,043 |
|
|
$ |
869 |
|
|
|
+20 |
% |
Production taxes |
|
|
176 |
|
|
|
90 |
|
|
|
+95 |
% |
|
|
310 |
|
|
|
170 |
|
|
|
+82 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses |
|
$ |
713 |
|
|
$ |
529 |
|
|
|
+35 |
% |
|
$ |
1,353 |
|
|
$ |
1,039 |
|
|
|
+30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
9.18 |
|
|
$ |
7.81 |
|
|
|
+18 |
% |
|
$ |
8.93 |
|
|
$ |
7.96 |
|
|
|
+12 |
% |
Production taxes |
|
|
3.01 |
|
|
|
1.61 |
|
|
|
+88 |
% |
|
|
2.66 |
|
|
|
1.57 |
|
|
|
+70 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses per Boe |
|
$ |
12.19 |
|
|
$ |
9.42 |
|
|
|
+30 |
% |
|
$ |
11.59 |
|
|
$ |
9.53 |
|
|
|
+22 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
Lease Operating Expenses (LOE)
LOE increased $98 million in the second quarter of 2008. The largest contributor to this
increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new
thermal heavy oil production from our Jackfish operations in Canada as well as new oil production
from Brazil. As these large-scale projects are in the early phases of production, per-unit
operating costs are higher than the per-unit costs for our overall portfolio of producing
properties. LOE also increased $17 million due to our 4% growth in production. Additionally, the
effects of changes in the exchange rate between the U.S. and Canadian dollar caused LOE to increase
$17 million. The exchange rate effect also contributed to the increase in LOE per Boe.
LOE increased $174 million in the first half of 2008. The largest contributor to this
increase, as well as the increase in LOE per Boe, was higher per-unit costs associated with new
thermal heavy oil production from our Jackfish operations in Canada as well as new oil production
from Brazil. LOE also increased $61 million due to our 7% growth in production. Furthermore,
changes in the exchange rate between the U.S. and Canadian dollar
also caused LOE to increase $46
million. This exchange rate also contributed to the increase in LOE per Boe.
Production Taxes
The following table details the changes in production taxes between the three months ended
June 30, 2008 and 2007 and the six months ended June 30, 2008 and 2007. The majority of our
production taxes are assessed on our U.S. onshore properties and are based on a fixed percentage of
revenues. Therefore, the changes due to revenues in the following table primarily relate to changes
in oil, gas and NGL revenues from our U.S. onshore properties.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
(In millions) |
|
2007 production taxes |
|
$ |
90 |
|
|
$ |
170 |
|
Change due to revenues |
|
|
58 |
|
|
|
100 |
|
Change due to rate |
|
|
28 |
|
|
|
40 |
|
|
|
|
|
|
|
|
2008 production taxes |
|
$ |
176 |
|
|
$ |
310 |
|
|
|
|
|
|
|
|
33
Depreciation, Depletion and Amortization Expenses (DD&A)
The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties
between the three and six months ended June 30, 2008 and 2007 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Production volumes (MMBoe) |
|
|
59 |
|
|
|
56 |
|
|
|
+4 |
% |
|
|
117 |
|
|
|
109 |
|
|
|
+7 |
% |
DD&A rate ($ per Boe) |
|
$ |
13.03 |
|
|
$ |
11.48 |
|
|
|
+14 |
% |
|
$ |
12.84 |
|
|
$ |
11.29 |
|
|
|
+14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
762 |
|
|
$ |
645 |
|
|
|
+18 |
% |
|
$ |
1,499 |
|
|
$ |
1,232 |
|
|
|
+22 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
The following table details the changes in DD&A of oil and gas properties between the three
months and six months ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
(In millions) |
|
2007 DD&A |
|
$ |
645 |
|
|
$ |
1,232 |
|
Change due to volumes |
|
|
26 |
|
|
|
86 |
|
Change due to rate |
|
|
91 |
|
|
|
181 |
|
|
|
|
|
|
|
|
2008 DD&A |
|
$ |
762 |
|
|
$ |
1,499 |
|
|
|
|
|
|
|
|
The 4% production increase during the second quarter of 2008 caused oil and gas property
related DD&A to increase $26 million. In addition, oil and gas property related DD&A increased $91
million due to a 14% increase in the DD&A rate. The largest contributor to the rate increase was
inflationary pressure on costs incurred during 2007 and 2008, as well as the estimated development
costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to
the rate increase include a higher Canadian-to-U.S. dollar exchange rate in 2008 and the transfer
of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling
activities.
The 7% production increase during the first half of 2008 caused oil and gas property related
DD&A to increase $86 million. In addition, oil and gas property related DD&A increased $181 million
due to a 14% increase in the DD&A rate. The largest contributor to the rate increase was
inflationary pressure on costs incurred during 2007 and 2008, as well as the estimated development
costs to be spent in future periods on proved undeveloped reserves. Other factors contributing to
the rate increase include a higher Canadian-to-U.S. dollar exchange rate in 2008 and the transfer
of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling
activities.
General and Administrative Expenses (G&A)
The following schedule includes the components of G&A expense for the three-month and
six-month periods ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, |
|
|
Six Months Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
|
(In millions) |
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Gross G&A |
|
$ |
307 |
|
|
$ |
222 |
|
|
|
+38 |
% |
|
$ |
584 |
|
|
$ |
434 |
|
|
|
+35 |
% |
Capitalized G&A |
|
|
(100 |
) |
|
|
(82 |
) |
|
|
+22 |
% |
|
|
(199 |
) |
|
|
(146 |
) |
|
|
+37 |
% |
Reimbursed G&A |
|
|
(27 |
) |
|
|
(27 |
) |
|
|
+1 |
% |
|
|
(57 |
) |
|
|
(56 |
) |
|
|
+3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
180 |
|
|
$ |
113 |
|
|
|
+59 |
% |
|
$ |
328 |
|
|
$ |
232 |
|
|
|
+41 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
34
Gross G&A increased $85 million in the second quarter of 2008 compared to the same period of
2007. The largest contributor to the increase was higher employee compensation and benefits costs
related to our workforce growth and industry inflation. Additionally, gross G&A increased $27
million due to accelerated expense recognition of share-based compensation. In the second quarter
of 2008, we modified the share-based compensation arrangements for certain members of senior
management (executives). The modified compensation arrangements provide that executives who meet
certain years-of-service and age criteria can retire and continue vesting in outstanding
share-based grants. This modification results in accelerated expense recognition as executives
approach the years-of-service and age criteria. Additionally, when the modification was made in the
second quarter of 2008, certain executives had already met the years-of-service and age criteria.
As a result, we recognized an additional $27 million of share-based compensation expense in the
second quarter of 2008 related to this modification. This additional expense would have been
recognized in future reporting periods if the modification had not been made and the executives
continued their employment at Devon.
The $18 million increase in capitalized G&A during the second quarter of 2008 is primarily due
to the higher employee compensation and benefits costs.
Gross G&A increased $150 million in the first half of 2008 compared to the same period of
2007. The largest contributor to the increase was higher employee compensation and benefits costs
related to our workforce growth and industry inflation. Additionally, gross G&A increased $27
million due to the accelerated expense recognition of share-based compensation discussed above.
The $53 million increase in capitalized G&A during the first half of 2008 is primarily due to
higher employee compensation and benefits costs.
Interest Expense
The following schedule includes the components of interest expense for the three-month and
six-month periods ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
110 |
|
|
$ |
125 |
|
|
$ |
236 |
|
|
$ |
253 |
|
Capitalized interest |
|
|
(25 |
) |
|
|
(24 |
) |
|
|
(56 |
) |
|
|
(47 |
) |
Other |
|
|
5 |
|
|
|
6 |
|
|
|
12 |
|
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
90 |
|
|
$ |
107 |
|
|
$ |
192 |
|
|
$ |
217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding decreased during the second quarter of 2008 and the first
half of 2008 primarily due to a decrease in outstanding borrowings. The decrease in borrowings
resulted largely from the use of proceeds from asset sales and cash flow from operations to repay
all commercial paper and credit facility borrowings in the second quarter of 2008.
Change in Fair Value of Non-Oil and Gas Financial Instruments
The following schedule includes the components of the change in fair value of non-oil and gas
financial instruments for the three months and six months ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30, |
|
|
Six Months
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Losses (gains) from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron common stock |
|
$ |
(195 |
) |
|
$ |
(146 |
) |
|
$ |
(82 |
) |
|
$ |
(152 |
) |
Option embedded in exchangeable debentures |
|
|
155 |
|
|
|
136 |
|
|
|
58 |
|
|
|
144 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
(40 |
) |
|
$ |
(10 |
) |
|
$ |
(24 |
) |
|
$ |
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Each reporting period, we recognize unrealized changes in the fair values of our investment in
14.2 million shares of Chevron common stock and the conversion option embedded in the debentures
exchangeable into shares of Chevron common stock. We calculate the fair value of our investment in
Chevron common stock using Chevrons published market price. The embedded option is not actively
traded in an established market. Therefore, we estimate its fair value
35
using quotes obtained from a broker for trades occurring near the valuation date. Because the
exchangeable debentures are due in August 2008, the embedded options recent fair value changes
largely coincide with changes in the market price of Chevrons common stock. As a result, when
Chevrons common stock price has increased from one valuation date to another, we have recognized a
gain on our investment and a loss on the embedded option. The inverse is also true.
The gain on our investment in Chevron common stock and loss on the embedded option during the
second quarter of 2008 were directly attributable to a $13.77 increase in the price per share of
Chevrons common stock during the second quarter of 2008. The gain on our investment in Chevron
common stock and loss on the embedded option during the second quarter of 2007 were directly
attributable to a $10.28 increase in the price per share of Chevrons common stock during the
second quarter of 2007.
The gain on our investment in Chevron common stock and loss on the embedded option during the
first half of 2008 were directly attributable to a $5.80 increase in the price per share of
Chevrons common stock during the first half of 2008. The gain on our investment in Chevron common
stock and loss on the embedded option during the first half of 2007 were directly attributable to a
$10.71 increase in the price per share of Chevrons common stock during the first half of 2007.
Income Taxes
The following table presents our total income tax expense related to continuing operations and
a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for the
three-month and six-month periods ended June 30, 2008 and 2007. The primary factors causing our
effective rates to vary from 2007 to 2008, and differ from the U.S. statutory rate, are discussed
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Total income tax expense (In millions) |
|
$ |
667 |
|
|
$ |
330 |
|
|
$ |
908 |
|
|
$ |
594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
Repatriations and tax policy election changes |
|
|
25 |
% |
|
|
|
|
|
|
14 |
% |
|
|
|
|
Canadian statutory rate reductions |
|
|
|
|
|
|
(2 |
%) |
|
|
|
|
|
|
(1 |
%) |
Other, primarily taxation on foreign operations |
|
|
(7 |
%) |
|
|
(4 |
%) |
|
|
(7 |
%) |
|
|
(4 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate |
|
|
53 |
% |
|
|
29 |
% |
|
|
42 |
% |
|
|
30 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
In the both the second quarter and six months ended June 30, 2008, our effective income tax
rate was higher than the U.S. statutory income tax rate largely due to two related factors. First,
in the second quarter of 2008, we repatriated $1.3 billion in earnings from certain foreign
subsidiaries to the United States. We also expect to repatriate approximately $1.5 billion in
earnings from foreign subsidiaries to the United States during the last six months of 2008. Second,
we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we
otherwise would pay to all relevant tax jurisdictions for the cash repatriations, as well as the
taxable gains associated with the sales of assets in West Africa. As a result of the repatriation
and tax policy election changes, we recognized additional tax expense of $312 million during the
second quarter of 2008. Of the $312 million, $295 million was recognized as current income tax
expense, and $17 million was recognized as deferred tax expense.
Excluding the $312 million of additional tax expense, our effective income tax rates would
have been 28% for both the second quarter of 2008 and the first half of 2008. These rates, as well
as the rates for the second quarter of 2007 and the first half of 2007, were lower than the U.S.
statutory income tax rate largely due to our foreign operations, which have statutory rates lower
than the U.S. statutory income tax rate. The 2007 rates were also impacted by a $30 million tax
benefit that we recognized as a result of a statutory rate reduction enacted by the Canadian
Federal government in the second quarter of 2007.
Additionally, we expect our effective income tax rate for the remainder of 2008 will
approximate the 28% rate applicable to the first half of 2008, excluding the $312 million of
additional tax expense.
36
Earnings from Discontinued Operations
Our discontinued operations consist of our operations in Egypt, which were sold in the fourth
quarter of 2007, and our operations in West Africa, including Equatorial Guinea, Gabon, Cote
DIvoire and other countries in the region.
Following are the components of earnings from discontinued operations for the three months and
six months ended June 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended June 30, |
|
|
Six Months
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Earnings from discontinued operations before income taxes |
|
$ |
851 |
|
|
$ |
128 |
|
|
$ |
1,040 |
|
|
$ |
265 |
|
Income tax expense |
|
|
144 |
|
|
|
48 |
|
|
|
235 |
|
|
|
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
$ |
707 |
|
|
$ |
80 |
|
|
$ |
805 |
|
|
$ |
157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations increased $627 million in the second quarter of 2008 and
increased $648 million in the first half of 2008. The largest contributor to these increases was
the recognition of after-tax gains totaling $647 million upon the sale of our assets in Equatorial
Guinea, Gabon and other countries in the second quarter of 2008.
Capital Resources, Uses and Liquidity
The following discussion of liquidity and capital resources 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, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
5,066 |
|
|
$ |
3,152 |
|
Sales of property and equipment |
|
|
108 |
|
|
|
37 |
|
Stock option exercises |
|
|
104 |
|
|
|
60 |
|
Net sales of short-term investments |
|
|
245 |
|
|
|
259 |
|
Cash received from discontinued operations |
|
|
1,746 |
|
|
|
|
|
Other |
|
|
55 |
|
|
|
17 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
7,324 |
|
|
|
3,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(3,867 |
) |
|
|
(2,990 |
) |
Net commercial paper repayments |
|
|
(1,004 |
) |
|
|
(183 |
) |
Net repayments of debt |
|
|
(1,497 |
) |
|
|
|
|
Repurchases of common stock |
|
|
(252 |
) |
|
|
(10 |
) |
Redemption of preferred stock |
|
|
(150 |
) |
|
|
|
|
Dividends |
|
|
(146 |
) |
|
|
(129 |
) |
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(6,916 |
) |
|
|
(3,312 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase from continuing operations |
|
|
408 |
|
|
|
213 |
|
Increase from discontinued operations, net |
|
|
83 |
|
|
|
82 |
|
of distributions to continuing operations
Effect of foreign exchange rates |
|
|
(19 |
) |
|
|
16 |
|
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
$ |
472 |
|
|
$ |
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
1,845 |
|
|
$ |
1,067 |
|
|
|
|
|
|
|
|
Short-term investments at end of period |
|
$ |
1 |
|
|
$ |
315 |
|
|
|
|
|
|
|
|
37
Operating Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash flow) continued to be the primary
source of capital and liquidity in the first half of 2008. Changes in operating cash flow are
largely due to the same factors that affect our net earnings, with the exception of those earnings
changes due to such noncash expenses as DD&A, financial instrument fair value changes and deferred
income tax expense. As a result, our operating cash flow increased in 2008 primarily due to the
increase in earnings as discussed in the Results of Operations section of this report.
During the first half of 2008, our operating cash flow was sufficient to fund our capital
expenditures. Additionally, during 2007, operating cash flow was sufficient to fund all of our
capital expenditures.
Other Sources of Cash
As needed, we utilize cash on hand and access our available credit under our credit facilities
and commercial paper program as sources of cash to supplement our operating cash flow.
Additionally, we sometimes acquire short-term investments to maximize our income on available cash
balances. As needed, we may reduce such short-term investment balances to further supplement our
operating cash flow. During 2008, we reduced our short-term investment balances by $245 million.
During 2007, we reduced our short-term investment balances by $259 million to supplement our
operating cash flow and fund debt repayments.
In 2008, another significant source of cash is the proceeds from our African divestiture
program. In the second quarter of 2008, we received $2.4 billion in proceeds ($1.7 billion net of
income taxes and purchase price adjustments) for sales of assets located in certain West African
countries, including Equatorial Guineathe largest individual transaction in the divestiture
program. Also, in conjunction with these asset sales, we repatriated an additional $1.3 billion of
earnings from certain foreign subsidiaries to the United States in the second quarter of 2008.
During 2008, we have used the proceeds from asset sales, repatriated funds and our operating
cash flow in excess of capital expenditures to fund debt repayments, common stock repurchases and
dividends on common and preferred stock.
Capital Expenditures
Following are the components of our capital expenditures for the first half of 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended June 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
2,082 |
|
|
$ |
1,526 |
|
U.S. Offshore |
|
|
538 |
|
|
|
300 |
|
Canada |
|
|
707 |
|
|
|
682 |
|
International |
|
|
274 |
|
|
|
269 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
3,601 |
|
|
|
2,777 |
|
Midstream |
|
|
205 |
|
|
|
171 |
|
Other |
|
|
61 |
|
|
|
42 |
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
3,867 |
|
|
$ |
2,990 |
|
|
|
|
|
|
|
|
Our capital expenditures consist of amounts related to our oil and gas exploration and
development operations, our midstream operations and other corporate activities. The vast majority
of our capital expenditures are for the acquisition, drilling or development of oil and gas
properties, which totaled $3.6 billion and $2.8 billion in the first six months of 2008 and 2007,
respectively. 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 exploration and development capital expenditures increased $824 million in the first six
months of 2008. The higher expenditures primarily relate to increased drilling activities in the
Barnett Shale, Gulf of Mexico and Carthage areas of the United States. Expenditures also increased
due to inflationary pressure driven by increased competition for field services.
38
Net Repayments of Debt
During the first half of 2008, we repaid $2.5 billion in outstanding credit facility and
commercial paper borrowings primarily with proceeds received from the sales of assets under our
African divestiture program and cash generated from operations. This compares to $183 million of
commercial paper borrowings we repaid during the first half of 2007.
Also during the first half of 2008, certain holders of exchangeable debentures exercised their
option to exchange their debentures for shares of Chevron common stock that we own prior to the
debentures August 15, 2008 maturity date. We have the option, in lieu of delivering shares of
Chevron common stock, to pay exchanging debenture holders an amount of cash equal to the market
value of Chevron common stock. We paid $47 million in cash to debenture holders who exercised their
exchange rights in the first half of 2008. This amount included the retirement of debentures with a
book value of $28 million and a $19 million reduction of the related embedded derivative options
balance.
Repurchases of Common Stock
During the first half of 2008, we repurchased 2.8 million shares for $302 million, or $106.01
per share. The 2.8 million shares include 2.0 million shares that were repurchased under our 50
million share program and 0.8 million shares that were repurchased under our ongoing, annual stock
repurchase program.
Redemption of Preferred Stock
On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 6.49% Series A
cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption
price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
Dividends
Our common stock dividends were $141 million (or a quarterly rate of $0.16 per share) and $124
million (or a quarterly rate of $0.14 per share) in the first half of 2008 and 2007, respectively.
The higher dividend rate was the primary cause of the increase in common dividends. We also paid $5
million of preferred stock dividends in the first six months of 2008 and 2007.
Liquidity
Our primary source of capital and liquidity has been our operating cash flow. Additionally, we
maintain revolving lines of credit and a commercial paper program which can be accessed as needed
to supplement operating cash flow. Other available sources of capital and liquidity include cash on
hand and the issuance of equity securities and long-term debt. Another major source of near-term
liquidity is proceeds from the sales of our operations in West Africa, including related
repatriations of earnings from certain foreign subsidiaries to the United States. In the second
quarter of 2008, we repatriated $1.3 billion in earnings. We expect to repatriate approximately
$1.5 billion during the last six months of 2008.
Operating Cash Flow
Our operating cash flow increased 55% to a record high of $5.2 billion in the first half of
2008. We expect operating cash flow to continue to be our primary source of liquidity. Our
operating cash flow is sensitive to many variables, the most volatile of which is pricing of the
oil, natural gas and NGLs produced. To mitigate some of the risk inherent in prices, we have
utilized various price collars to set minimum and maximum prices on a portion of our production. We
have also utilized various price swap contracts and fixed-price physical delivery contracts to fix
the price of a portion of our future oil and natural gas production. As disclosed in Item 7A.
Quantitative and Qualitative Disclosures of Market Risk of our 2007 Annual Report on Form 10-K/A,
approximately 64% of our estimated 2008 natural gas production and 12% of our estimated oil
production are subject to either price collars, swaps or fixed-price contracts. Additionally,
subsequent to the filing of our 2007 Annual Report, we have entered into additional gas price
collars, which represent approximately 10% of our estimated 2009 natural gas production. The key
terms of these 2009 price collars are included in Item 3. Quantitative and Qualitative Disclosures
of Market Risk of this report.
39
Interest Rate Swaps
As of June 30, 2008, we had long-term debt of $4.8 billion. All of this long-term debt bears
interest at fixed rates with an overall weighted-average rate of 7.6%. In July 2008, we entered
into interest rate swaps to mitigate a portion of the fair value effects of interest rate
fluctuations on our fixed-rate debt. Under the terms of these swaps, we receive a fixed rate and
pay a variable rate on a total notional amount of $1.05 billion. The key terms of these interest
rate swaps are presented in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable |
|
|
Notional |
|
|
Fixed Rate Received |
|
|
Rate Paid |
|
Expiration |
(In millions) |
|
|
|
|
|
|
|
|
|
$ |
500 |
|
|
|
3.90 |
% |
|
Federal funds rate |
|
July 18, 2013 |
$ |
300 |
|
|
|
4.30 |
% |
|
Six month LIBOR |
|
July 18, 2011 |
$ |
250 |
|
|
|
3.85 |
% |
|
Federal funds rate |
|
July 22, 2013 |
|
|
|
|
|
|
|
|
|
$ |
1,050 |
|
|
|
4.00 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Including the effects of these swaps, the weighted-average interest rate related to our
fixed-rate debt was 7.2% as of July 31, 2008.
Credit Availability
In April 2008, we extended the maturity of $2.0 billion of our existing $2.5 billion
five-year, syndicated, unsecured revolving line of credit (the Senior Credit Facility) from April
7, 2012 to April 7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not
approve a maturity date extension. Therefore, the maturity date for $0.5 billion of the Senior
Credit Facility remains at April 7, 2012.
On August 7, 2007, we established a $1.5 billion 364-day, syndicated, unsecured revolving
senior credit facility (the Short-Term Facility). This facility matured on August 5, 2008 and was
not extended. As a result of the Short-Term Facilitys maturity, our commercial paper program
capacity decreased from $3.5 billion to $2.0 billion.
The Senior Credit Facility contains only one material financial covenant. This covenant
requires our ratio of total funded debt to total capitalization, as defined in the credit
agreement, to be no more than 65%. As of June 30, 2008, we were in compliance with this covenant.
Our debt-to-capitalization ratio at June 30, 2008, as calculated pursuant to the terms of the
agreement, was 16.3%.
As of August 5, 2008, our available capacity under our Senior Credit Facility was
approximately $2.4 billion. This available capacity is net of $140 million of outstanding letters
of credit. There were no outstanding commercial paper or Senior Credit Facility borrowings as of
August 5, 2008.
Debt Ratings
During the first quarter of 2008, Standard and Poors upgraded our credit rating from BBB with
a positive outlook to BBB+ with a stable outlook. During the second quarter of 2008, Fitch upgraded
our credit rating from BBB with a positive outlook to BBB+ with a stable outlook. We are not aware
of any potential downgrades or changes contemplated by the other rating agencies as of July 31,
2008.
Property Divestitures
In the second quarter of 2008, we made significant progress toward completion of our African
divestiture program. We completed the sales of assets in certain West African countries, including
Equatorial Guineathe largest individual transaction in the divestiture program. As a result of the
sales, we received proceeds of $2.4 billion ($1.7 billion net of income taxes and purchase price
adjustments).
We have also entered into agreements to sell our operations in Cote DIvoire and other
countries located in West Africa for approximately $250 million. Devon is obtaining the necessary
partner and government approvals for these properties and expects to complete the remaining sales
during the third quarter of 2008.
40
Capital Expenditures
In February 2008, we provided guidance for our 2008 capital expenditures. At that time, we
estimated capital expenditures for our oil and gas exploration and development operations would
range from $5.6 billion to $5.9 billion.
With higher than expected realized oil and gas prices through the first half of 2008 and the
proceeds received from sales of assets in West Africa in the second quarter of 2008, we now have
robust cash flow and liquidity that can be leveraged to optimize Devons value per share. In
addition to repaying our commercial paper and credit facility borrowings and restarting our
substantial share repurchase program, we are also increasing our planned 2008 investment in capital
projects. Therefore, we have increased our estimate of 2008 capital expenditures for oil and gas
exploration and development operations, which are now expected to range from $7.2 billion to $7.5
billion. A significant portion of this incremental capital is directed to additional acreage
capture in North America and increased investment in the Lower Tertiary trend.
Common Stock Repurchase Programs
Our Board of Directors approved an ongoing, annual stock repurchase program to minimize
dilution resulting from restricted stock issued to, and options exercised by, employees. In 2008,
the repurchase program authorizes the repurchase of up to 4.8 million shares or a cost of $422
million, whichever amount is reached first. Our Board of Directors also approved a separate program
to repurchase up to 50 million shares, which expires on December 31, 2009. As of June 30, 2008, up
to 4.0 million shares or $358 million can be repurchased under the ongoing, annual repurchase
program and up to 48.0 million shares can be repurchased under the 50 million share repurchase
program.
Auction Rate Securities
At December 31, 2007, we held $372 million of auction rate securities, which are asset-backed
securities that have an auction rate reset feature. Our auction rate securities are rated AAAthe
highest ratingby one or more rating agencies and are collateralized by student loans that are
substantially guaranteed by the United States government. Although our auction rate securities
generally have contractual maturities of more than 20 years, the underlying interest rates on such
securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities
were generally priced and subsequently traded as short-term investments because of the interest
rate reset feature. As a result, we considered our auction rate securities to be short-term
investments at the end of 2007.
During the first half of 2008, we reduced our auction rate securities holdings to $127 million
as of June 30, 2008. However, since February 8, 2008 we have experienced difficulty selling our
securities due to the failure of the auction mechanism, which provides liquidity to these
securities. An auction failure means that the parties wishing to sell securities could not do so.
The securities for which auctions have failed will continue to accrue interest and be auctioned
every seven to 28 days until the auction succeeds, the issuer calls the securities or the
securities mature.
From February 2008, when auctions began failing, to June 30, 2008, issuers redeemed $26
million of our auction rate securities holdings at par. Additionally, our auction rate securities
holdings as of June 30, 2008 include approximately $1 million of securities that were called at par
value by the issuer and were repaid on July 10, 2008. These called securities continue to be
considered short-term investments as of June 30, 2008. However, based on continued auction failures
and the current market for our auction rate securities, we have classified the $126 million of
securities that have not been called as long-term investments as of June 30, 2008 and generally not
available for short-term liquidity needs.
As of December 31, 2007, we estimated the fair values of our short-term auction rate
securities using quoted market prices. However, due to the auction failures discussed above and the
lack of an active market for our long-term securities, quoted market prices for the vast majority
of these securities were not available as of June 30, 2008. Therefore, we used valuation techniques
that rely on unobservable inputs to estimate the fair values of our long-term auction rate
securities as of June 30, 2008. These inputs were based on the AAA credit rating of the securities,
the probability of full repayment of the securities considering the United States government
guarantees of substantially all of the underlying student loans and the collection of all accrued
interest to date. As a result of using these inputs, we concluded the estimated fair values of our
long-term auction rate securities approximated the par values as of June 30, 2008. At this time, we
do not believe the values of our long-term securities are impaired.
41
Recently Issued Accounting Standards Not Yet Adopted
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 141(R), Business Combinations, which replaces Statement No. 141.
Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be
identified and the acquisition method of accounting (previously called the purchase method) be used
for all business combinations. Statement No. 141(R)s scope is broader than that of Statement No.
141, which applied only to business combinations in which control was obtained by transferring
consideration. By applying the acquisition method to all transactions and other events in which one
entity obtains control over one or more other businesses, Statement No. 141(R) improves the
comparability of the information about business combinations provided in financial reports.
Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and
measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the
acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. We will evaluate how the new requirements
of Statement No. 141(R) would impact any business combinations completed in 2009 or thereafter.
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160,
Noncontrolling Interests in Consolidated Financial Statementsan amendment of Accounting Research
Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of
equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160
establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a
subsidiary must be reported as a component of consolidated equity separate from the parents
equity. Additionally, the amounts of consolidated net income attributable to both the parent and
the noncontrolling interest must be reported separately on the face of the income statement.
Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier
adoption is prohibited. We do not expect the adoption of Statement No. 160 to have a material
impact on our financial statements and related disclosures.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,
Disclosures about Derivative Instruments and Hedging Activitiesan amendment of FASB Statement No.
133. Statement No. 161 requires additional disclosures about derivative and hedging activities and
is effective for fiscal years and interim periods beginning after November 15, 2008. We are
evaluating the impact the adoption of Statement No. 161 will have on our financial statement
disclosures. However, our adoption of Statement No. 161 will not affect our current accounting for
derivative and hedging activities.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Gas
Collar Contracts
We have various financial price swaps to fix the price of a portion of our 2008 gas
production. We also have various financial price collars to set minimum and maximum prices on a
portion of our 2008 oil and gas production. The key terms to these 2008 price swaps and collars are
included in Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our 2007
Annual Report on Form 10-K/A.
We have also entered into various financial price collars to set minimum and maximum prices on
approximately 10% of our expected 2009 gas production. The key terms to our 2009 gas financial
collar contracts are not included in our 2007 Annual Report on Form 10-K/A but are presented in the
following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Price Collar Contracts |
|
|
|
|
|
|
Floor Price |
|
Ceiling Price |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Floor |
|
Average |
|
Ceiling |
|
Average |
|
|
Volume |
|
Range |
|
Floor Price |
|
Range |
|
Ceiling Price |
Period |
|
(MMBtu/d) |
|
($/MMBtu) |
|
($/MMBtu) |
|
($/MMBtu) |
|
($/MMBtu) |
First quarter. |
|
|
300,000 |
|
|
$ |
8.00 - $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 - $14.00 |
|
|
$ |
11.97 |
|
Second quarter |
|
|
300,000 |
|
|
$ |
8.00 - $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 - $14.00 |
|
|
$ |
11.97 |
|
Third quarter. |
|
|
300,000 |
|
|
$ |
8.00 - $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 - $14.00 |
|
|
$ |
11.97 |
|
Fourth quarter |
|
|
300,000 |
|
|
$ |
8.00 - $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 - $14.00 |
|
|
$ |
11.97 |
|
2009 average |
|
|
300,000 |
|
|
$ |
8.00 - $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 - $14.00 |
|
|
$ |
11.97 |
|
42
The fair values of all our oil and gas hedging instruments are largely determined by estimates
of the forward curves of relevant oil and gas price indexes. At June 30, 2008, a 10% increase in
these forward curves would have increased the net liabilities recorded for our 2008 and 2009
commodity hedging instruments by approximately $550 million.
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, 2008 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 2008 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
43
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 2007 Annual Report on Form 10-K/A.
Item 1A. Risk Factors
There have been no material changes to the information included in Item 1A. Risk Factors in
our 2007 Annual Report on Form 10-K/A.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Maximum Number of |
|
|
|
|
|
|
|
|
|
|
Shares Purchased as |
|
Shares that May Yet |
|
|
Total |
|
Average Price |
|
Part of Publicly |
|
Be Purchased Under |
|
|
Number of Shares |
|
Paid |
|
Announced Plans or |
|
the Plans or |
Period |
|
Purchased |
|
per Share |
|
Programs (1) |
|
Programs (1) |
April |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
53,991,900 |
|
May |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
53,991,900 |
|
June |
|
|
2,036,715 |
|
|
$ |
116.57 |
|
|
|
2,036,715 |
|
|
|
51,955,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2,036,715 |
|
|
$ |
116.57 |
|
|
|
2,036,715 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Our Board of Directors approved an ongoing, annual stock repurchase program to
minimize dilution resulting from restricted stock issued to, and options exercised by,
employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million
shares or a cost of $422 million, whichever amount is reached first. Our Board of
Directors also approved a separate program to repurchase up to 50 million shares, which
expires on December 31, 2009. All shares repurchased during the second quarter of 2008
were repurchased under the 50 million share repurchase program. As of June 30, 2008, up
to 4.0 million shares or $358 million can be repurchased under the ongoing, annual
repurchase program and up to 48.0 million shares can be repurchased under the 50 million
share repurchase program. |
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
(a) Devons Annual Meeting of Stockholders was held in Oklahoma City, Oklahoma at 8:00 a.m.,
local time, on Wednesday, June 4, 2008.
(b) Proxies for the meeting were solicited pursuant to Regulation 14 under the Securities
Exchange Act of 1934, as amended. There was no solicitation in opposition to the nominees for
election as Directors as listed in the Proxy Statement for the June 4, 2008 meeting and all
nominees were elected.
(c) A total of 401,657,101 shares of Devons common stock outstanding and entitled to vote
were present at the June 4, 2008 meeting in person or by proxy, representing approximately 90.11%
of the total outstanding shares. The matters voted upon were as follows:
44
1. The election of three Directors to serve on Devons Board of Directors until the 2011
Annual Meeting of Stockholders. A total of at least 98.65% of all voted shares were cast for
approval of each nominee. The vote tabulation with respect to each nominee was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authority |
Nominee |
|
For |
|
Withheld |
David A. Hager |
|
|
396,269,943 |
|
|
|
5,387,158 |
|
John A. Hill |
|
|
396,241,980 |
|
|
|
5,415,121 |
|
Mary P. Ricciardello |
|
|
396,253,911 |
|
|
|
5,403,190 |
|
2. Ratification of KPMG LLP as the Companys Independent Auditors for 2008. A total of 97.99%
of all voted shares were cast for ratification of KPMG LLP. The results of the votes were as
follows:
|
|
|
|
|
FOR: |
|
|
393,574,431 |
|
AGAINST: |
|
|
4,480,321 |
|
ABSTAIN: |
|
|
3,602,349 |
|
3. The adoption of an amendment to the Restated Certificate of Incorporation to increase the
number of authorized shares of common stock. A total of 97.07% of all voted shares were cast to
increase the number of authorized shares of common stock.
|
|
|
|
|
FOR: |
|
|
389,884,929 |
|
AGAINST: |
|
|
8,003,108 |
|
ABSTAIN: |
|
|
3,769,064 |
|
4. The adoption of an amendment to the Restated Certificate of Incorporation to provide for
the annual election of directors. A total of 98.06% of all voted shares were cast to provide for
the annual election of directors.
|
|
|
|
|
FOR: |
|
|
393,850,136 |
|
AGAINST: |
|
|
4,165,847 |
|
ABSTAIN: |
|
|
3,641,118 |
|
Item 5. Other Information
None.
45
Item 6. Exhibits
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
|
|
|
Exhibit |
|
|
Number |
|
Description |
3.1
|
|
Registrants Certificate of Amendment of Restated Certificate of Incorporation. |
|
|
|
10.1
|
|
Form of Amendment to Nonqualified Stock Option Award Agreements under the
Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and
Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Daryl G. Smette and Lyndon C. Taylor. * |
|
|
|
10.2
|
|
Form of Amendment to Restricted Stock Award Agreements under the Devon Energy
Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J.
Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph,
Darryl G. Smette and Lyndon C. Taylor. * |
|
|
|
10.3
|
|
Form of Non-Management Director Nonqualified Stock Option Award Agreement
under the Devon Energy Corporation 2005 Long-Term Incentive Plan between
Registrant and all Non-Management Directors.* |
|
|
|
10.4
|
|
Form of Non-Management Director Restricted Stock Award Agreement under the
Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and
all Non-Management Directors.* |
|
|
|
31.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of Registrant,
pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2
|
|
Certification of Danny J. Heatly, Vice President Accounting and Chief
Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of Registrant,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of Danny J. Heatly, Vice President Accounting and Chief
Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
* |
|
Compensatory plans or arrangements |
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 7, 2008
|
|
/s/ Danny J. Heatly
|
|
|
|
|
|
|
|
|
|
Danny J. Heatly |
|
|
|
|
Vice President Accounting and Chief Accounting Officer |
|
|
46
INDEX TO EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Description |
3.1
|
|
Registrants Certificate of Amendment of Restated Certificate of Incorporation. |
|
|
|
10.1
|
|
Form of Amendment to Nonqualified Stock Option Award Agreements under the
Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and
Stephen J. Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W.
Rudolph, Daryl G. Smette and Lyndon C. Taylor. * |
|
|
|
10.2
|
|
Form of Amendment to Restricted Stock Award Agreements under the Devon Energy
Corporation 2005 Long-Term Incentive Plan between Registrant and Stephen J.
Hadden, R. Alan Marcum, J. Larry Nichols, John Richels, Frank W. Rudolph,
Darryl G. Smette and Lyndon C. Taylor. * |
|
|
|
10.3
|
|
Form of Non-Management Director Nonqualified Stock Option Award Agreement
under the Devon Energy Corporation 2005 Long-Term Incentive Plan between
Registrant and all Non-Management Directors.* |
|
|
|
10.4
|
|
Form of Non-Management Director Restricted Stock Award Agreement under the
Devon Energy Corporation 2005 Long-Term Incentive Plan between Registrant and
all Non-Management Directors.* |
|
|
|
31.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of Registrant,
pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2
|
|
Certification of Danny J. Heatly, Vice President Accounting and Chief
Accounting Officer of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer of Registrant,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of Danny J. Heatly, Vice President Accounting and Chief
Accounting Officer of Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
* |
|
Compensatory plans or arrangements |
47