e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended September 30, 2008
or
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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 October 31, 2008, 441.5 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 at which depository institutions lend balances at
the Federal Reserve to other depository institutions overnight.
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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September 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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$ |
1,193 |
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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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1,710 |
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1,779 |
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Current assets held for sale |
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88 |
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120 |
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Other current assets, including $142 million at fair value in 2008 |
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427 |
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279 |
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Total current assets |
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3,419 |
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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 ($4,073 and $3,417 excluded from amortization
in 2008 and 2007, respectively) |
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53,750 |
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48,473 |
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Less accumulated depreciation, depletion and amortization |
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22,300 |
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20,394 |
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31,450 |
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28,079 |
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Investment in Chevron Corporation common stock, at fair value |
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1,170 |
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1,324 |
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Goodwill |
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5,966 |
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6,172 |
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Long-term assets held for sale |
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19 |
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1,512 |
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Other long-term assets, including $158 million at fair value in 2008 |
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631 |
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455 |
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Total assets |
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$ |
42,655 |
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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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$ |
1,559 |
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$ |
1,360 |
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Revenues and royalties due to others |
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775 |
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578 |
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Income taxes payable |
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188 |
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97 |
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Short-term debt |
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1,004 |
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Current portion of asset retirement obligation, at fair value |
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115 |
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82 |
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Current liabilities associated with assets held for sale |
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12 |
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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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3,059 |
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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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4,837 |
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6,283 |
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Derivative financial instruments, at fair value |
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488 |
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Asset retirement obligation, at fair value |
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1,456 |
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1,236 |
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Long-term liabilities associated with assets held for sale |
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1 |
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404 |
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Other long-term liabilities |
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833 |
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699 |
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Deferred income taxes |
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7,179 |
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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 $0.10 par value. Authorized 1.0 billion shares;
issued 441.4 million and 444.2 million shares in 2008 and 2007, respectively |
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44 |
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44 |
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Additional paid-in capital |
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6,219 |
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6,743 |
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Retained earnings |
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17,265 |
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12,813 |
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Accumulated other comprehensive income |
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1,762 |
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2,405 |
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Total stockholders equity |
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25,290 |
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22,006 |
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Commitments and contingencies (Note 9)
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Total liabilities and stockholders equity |
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$ |
42,655 |
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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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Nine Months Ended |
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September 30, |
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September 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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$ |
1,296 |
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$ |
905 |
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$ |
4,001 |
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$ |
2,461 |
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Gas sales |
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2,107 |
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1,175 |
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5,947 |
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3,787 |
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NGL sales |
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362 |
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242 |
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1,069 |
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643 |
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Net gain (loss) on oil and gas derivative financial instruments |
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1,592 |
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7 |
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(411 |
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1 |
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Marketing and midstream revenues |
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621 |
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434 |
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1,895 |
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1,273 |
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Total revenues |
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5,978 |
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2,763 |
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12,501 |
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8,165 |
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Expenses and other income, net: |
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Lease operating expenses |
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591 |
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457 |
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1,634 |
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1,326 |
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Production taxes |
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152 |
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85 |
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462 |
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255 |
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Marketing and midstream operating costs and expenses |
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452 |
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301 |
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1,349 |
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912 |
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Depreciation, depletion and amortization of oil and gas properties |
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781 |
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705 |
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2,280 |
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1,937 |
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Depreciation and amortization of non-oil and gas properties |
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67 |
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51 |
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186 |
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146 |
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Accretion of asset retirement obligation |
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22 |
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19 |
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66 |
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55 |
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General and administrative expenses |
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146 |
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126 |
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474 |
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358 |
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Interest expense |
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69 |
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108 |
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261 |
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325 |
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Change in fair value of other financial instruments |
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46 |
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(22 |
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22 |
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(31 |
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Other income, net |
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(83 |
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(28 |
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(121 |
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(71 |
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Total expenses and other income, net |
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2,243 |
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1,802 |
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6,613 |
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5,212 |
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Earnings from continuing operations before income tax expense |
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3,735 |
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961 |
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5,888 |
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2,953 |
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Income tax expense: |
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Current |
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226 |
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96 |
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743 |
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459 |
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Deferred |
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1,000 |
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221 |
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1,391 |
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452 |
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Total income tax expense |
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1,226 |
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317 |
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2,134 |
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911 |
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Earnings from continuing operations |
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2,509 |
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644 |
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3,754 |
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2,042 |
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Discontinued operations: |
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Earnings from discontinued operations before income tax expense |
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93 |
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177 |
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1,133 |
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442 |
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Income tax (benefit) expense |
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(16 |
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86 |
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219 |
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194 |
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Earnings from discontinued operations |
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109 |
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91 |
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914 |
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248 |
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Net earnings |
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2,618 |
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735 |
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4,668 |
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2,290 |
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Preferred stock dividends |
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2 |
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5 |
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7 |
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Net earnings applicable to common stockholders |
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$ |
2,618 |
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$ |
733 |
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$ |
4,663 |
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$ |
2,283 |
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Basic net earnings per share: |
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Earnings from continuing operations |
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$ |
5.67 |
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$ |
1.45 |
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$ |
8.44 |
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$ |
4.57 |
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Earnings from discontinued operations |
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0.25 |
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0.20 |
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2.06 |
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0.56 |
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Net earnings |
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$ |
5.92 |
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$ |
1.65 |
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$ |
10.50 |
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$ |
5.13 |
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Diluted net earnings per share: |
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Earnings from continuing operations |
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$ |
5.63 |
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$ |
1.43 |
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$ |
8.36 |
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$ |
4.52 |
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Earnings from discontinued operations |
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0.24 |
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0.20 |
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2.04 |
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|
0.55 |
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Net earnings |
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$ |
5.87 |
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$ |
1.63 |
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$ |
10.40 |
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$ |
5.07 |
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Weighted average common shares outstanding: |
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Basic |
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442 |
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445 |
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444 |
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445 |
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Diluted |
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446 |
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450 |
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448 |
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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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Nine Months Ended |
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|
September 30, |
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|
September 30, |
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|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Net earnings |
|
$ |
2,618 |
|
|
$ |
735 |
|
|
$ |
4,668 |
|
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$ |
2,290 |
|
Foreign currency translation: |
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Change in cumulative translation adjustment |
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(386 |
) |
|
|
579 |
|
|
|
(679 |
) |
|
|
1,311 |
|
Income tax benefit (expense) |
|
|
15 |
|
|
|
(33 |
) |
|
|
29 |
|
|
|
(74 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
(371 |
) |
|
|
546 |
|
|
|
(650 |
) |
|
|
1,237 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition
of net actuarial loss and prior service cost in net earnings |
|
|
4 |
|
|
|
4 |
|
|
|
12 |
|
|
|
12 |
|
Income tax expense |
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(5 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
2 |
|
|
|
2 |
|
|
|
7 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive (loss) income, net of tax |
|
|
(369 |
) |
|
|
548 |
|
|
|
(643 |
) |
|
|
1,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
2,249 |
|
|
$ |
1,283 |
|
|
$ |
4,025 |
|
|
$ |
3,533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) |
|
Nine Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
$ |
1 |
|
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,743 |
|
|
$ |
12,813 |
|
|
$ |
2,405 |
|
|
$ |
|
|
|
$ |
22,006 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,668 |
|
|
|
|
|
|
|
|
|
|
|
4,668 |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(643 |
) |
|
|
|
|
|
|
(643 |
) |
Stock option exercises |
|
|
|
|
|
|
4 |
|
|
|
1 |
|
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
|
|
109 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(681 |
) |
|
|
(681 |
) |
Common stock retired |
|
|
|
|
|
|
(7 |
) |
|
|
(1 |
) |
|
|
(684 |
) |
|
|
|
|
|
|
|
|
|
|
685 |
|
|
|
|
|
Redemption of preferred stock |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(149 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(150 |
) |
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(211 |
) |
|
|
|
|
|
|
|
|
|
|
(211 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
139 |
|
Excess tax benefits on share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2008 |
|
$ |
|
|
|
|
441 |
|
|
$ |
44 |
|
|
$ |
6,219 |
|
|
$ |
17,265 |
|
|
$ |
1,762 |
|
|
$ |
|
|
|
$ |
25,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,290 |
|
|
|
|
|
|
|
|
|
|
|
2,290 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,243 |
|
|
|
|
|
|
|
1,243 |
|
Stock option exercises |
|
|
|
|
|
|
3 |
|
|
|
1 |
|
|
|
70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(138 |
) |
|
|
(138 |
) |
Common stock retired |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
(139 |
) |
|
|
|
|
|
|
|
|
|
|
139 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(186 |
) |
|
|
|
|
|
|
|
|
|
|
(186 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
(7 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
92 |
|
Excess tax benefits on share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of September 30, 2007 |
|
$ |
1 |
|
|
|
445 |
|
|
$ |
45 |
|
|
$ |
6,883 |
|
|
$ |
11,564 |
|
|
$ |
2,339 |
|
|
$ |
|
|
|
$ |
20,832 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
4,668 |
|
|
$ |
2,290 |
|
Earnings from discontinued operations, net of tax |
|
|
(914 |
) |
|
|
(248 |
) |
Adjustments to reconcile earnings from continuing operations
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
2,466 |
|
|
|
2,083 |
|
Deferred income tax expense |
|
|
1,391 |
|
|
|
452 |
|
Net unrealized (gain) loss on oil and gas derivative financial instruments |
|
|
(140 |
) |
|
|
30 |
|
Other noncash charges |
|
|
217 |
|
|
|
94 |
|
(Increase) decrease in assets: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
32 |
|
|
|
(12 |
) |
Other current assets |
|
|
(85 |
) |
|
|
(65 |
) |
Other long-term assets |
|
|
(63 |
) |
|
|
(53 |
) |
Increase (decrease) in liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
|
223 |
|
|
|
113 |
|
Revenues and royalties due to others |
|
|
278 |
|
|
|
(2 |
) |
Income taxes payable |
|
|
36 |
|
|
|
139 |
|
Other current liabilities |
|
|
(124 |
) |
|
|
(78 |
) |
Other long-term liabilities |
|
|
94 |
|
|
|
(4 |
) |
|
|
|
|
|
|
|
Cash provided by operating activities continuing operations |
|
|
8,079 |
|
|
|
4,739 |
|
Cash provided by operating activities discontinued operations |
|
|
102 |
|
|
|
370 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
8,181 |
|
|
|
5,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from sales of property and equipment |
|
|
116 |
|
|
|
39 |
|
Capital expenditures |
|
|
(6,179 |
) |
|
|
(4,477 |
) |
Purchases of short-term investments |
|
|
(50 |
) |
|
|
(659 |
) |
Redemptions of short-term and long-term investments |
|
|
297 |
|
|
|
892 |
|
|
|
|
|
|
|
|
Cash used in investing activities continuing operations |
|
|
(5,816 |
) |
|
|
(4,205 |
) |
Cash provided by (used in) investing activities discontinued operations |
|
|
1,854 |
|
|
|
(153 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(3,962 |
) |
|
|
(4,358 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Credit facility repayments |
|
|
(3,191 |
) |
|
|
|
|
Credit facility borrowings |
|
|
1,741 |
|
|
|
400 |
|
Net commercial paper repayments |
|
|
(1,004 |
) |
|
|
(129 |
) |
Principal payments on debt |
|
|
(1,031 |
) |
|
|
(166 |
) |
Preferred stock redemption |
|
|
(150 |
) |
|
|
|
|
Proceeds from stock option exercises |
|
|
109 |
|
|
|
71 |
|
Repurchases of common stock |
|
|
(665 |
) |
|
|
(133 |
) |
Dividends paid on common and preferred stock |
|
|
(216 |
) |
|
|
(193 |
) |
Excess tax benefits related to share-based compensation |
|
|
58 |
|
|
|
20 |
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(4,349 |
) |
|
|
(130 |
) |
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
(47 |
) |
|
|
44 |
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
|
|
(177 |
) |
|
|
665 |
|
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) |
|
$ |
1,196 |
|
|
$ |
1,421 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data: |
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest) |
|
$ |
298 |
|
|
$ |
226 |
|
Income taxes paid continuing and discontinued operations |
|
$ |
1,162 |
|
|
$ |
293 |
|
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 September 30, 2008 and Devons results of operations and cash flows for
the three-month and nine-month periods ended September 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 nine months of 2008, Devon reduced its auction rate securities holdings to
$125 million. However, since February 8, 2008, Devon has experienced difficulty selling its
securities due to the failure of the auction mechanism, which provided 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 September 30, 2008, issuers redeemed $27
million of Devons auction rate securities holdings at par. Additionally, Devons auction rate
securities holdings as of September 30, 2008, include approximately $1 million of securities that
were called at par value by the issuer and were repaid on October 1, 2008. These called securities
are classified as short-term investments in the accompanying September 30, 2008 consolidated
balance sheet. However, based on continued auction failures and the current market for Devons
auction rate securities, Devon has classified the $124 million of securities that have not been
called as of September 30, 2008 as long-term investments. These securities are included in other
long-term assets in the accompanying September 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. Other Current Assets
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008 |
|
|
December 31, 2007 |
|
|
|
(In millions) |
|
Inventories |
|
$ |
217 |
|
|
$ |
144 |
|
Derivative financial instruments, at fair value |
|
|
142 |
|
|
|
12 |
|
Other current assets |
|
|
68 |
|
|
|
123 |
|
|
|
|
|
|
|
|
Total |
|
$ |
427 |
|
|
$ |
279 |
|
|
|
|
|
|
|
|
3. 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. All
of the assets in these countries were sold prior to September 30, 2008. Additional information
regarding Devons Egyptian and West African operations, which are presented as discontinued in the
accompanying financial statements, is provided in Note 13.
Asset Retirement Obligations (ARO)
The following is a summary of the changes in Devons ARO for the first nine months of 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Asset retirement obligation as of beginning of period |
|
$ |
1,318 |
|
|
$ |
857 |
|
Liabilities incurred |
|
|
48 |
|
|
|
44 |
|
Liabilities settled |
|
|
(59 |
) |
|
|
(52 |
) |
Revision of estimated obligation |
|
|
244 |
|
|
|
311 |
|
Accretion expense on discounted obligation |
|
|
66 |
|
|
|
55 |
|
Foreign currency translation adjustment |
|
|
(46 |
) |
|
|
85 |
|
|
|
|
|
|
|
|
Asset retirement obligation as of end of period |
|
|
1,571 |
|
|
|
1,300 |
|
Less current portion |
|
|
115 |
|
|
|
54 |
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
1,456 |
|
|
$ |
1,246 |
|
|
|
|
|
|
|
|
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
During the first nine months of 2008 and 2007, Devon recognized increases of $244 million and
$311 million, respectively, to its ARO. The ARO increased $162 million in 2008 as a result of an
overall increase in abandonment cost estimates and the effect of a decrease in the discount rate
used to present value the obligations. In the third quarter of 2008, the ARO increased $82 million
as a result of higher abandonment cost estimates related to certain offshore platforms that were
destroyed by Hurricane Ike. See additional discussion regarding this revision in Note 9 Hurricane
Contingencies. 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.
4. 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 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.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate
volatility. In the third quarter of 2008, Devon entered into interest rate swaps to mitigate a
portion of the fair value effects of interest rate fluctuations on its fixed-rate debt. Under the
terms of these swaps, Devon receives a fixed rate and pays a variable rate on a total notional
amount of $1.05 billion.
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, price collars
and interest rate swaps are also recorded in the statement of operations.
Commodity Derivative Financial Instruments
The following tables present the fair values included in the accompanying balance sheet and
the cash settlements and net unrealized gains and losses included in the accompanying statement of
operations associated with Devons commodity derivative financial instruments.
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008 |
|
|
December 31, 2007 |
|
|
|
(In millions) |
|
Fair values: |
|
|
|
|
|
|
|
|
Other current assets: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
39 |
|
|
$ |
12 |
|
Gas price collars |
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
|
Total commodity derivative financial instruments, other current assets |
|
$ |
137 |
|
|
$ |
12 |
|
|
|
|
|
|
|
|
Other long-term assets gas price collars |
|
$ |
16 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Accrued expenses and other current liabilities oil collars |
|
$ |
1 |
|
|
$ |
|
|
|
|
|
|
|
|
|
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
(115 |
) |
|
$ |
14 |
|
|
$ |
(276 |
) |
|
$ |
29 |
|
Gas price collars |
|
|
(125 |
) |
|
|
|
|
|
|
(275 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received |
|
|
(240 |
) |
|
|
14 |
|
|
|
(551 |
) |
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
645 |
|
|
|
(7 |
) |
|
|
27 |
|
|
|
(26 |
) |
Gas price collars |
|
|
1,142 |
|
|
|
|
|
|
|
114 |
|
|
|
(4 |
) |
Oil price collars |
|
|
45 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) on fair value changes |
|
|
1,832 |
|
|
|
(7 |
) |
|
|
140 |
|
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on oil and gas derivative financial
instruments |
|
$ |
1,592 |
|
|
$ |
7 |
|
|
$ |
(411 |
) |
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Rate Swaps
As of September 30, 2008, Devons interest rate swaps had a positive fair value of
$23
million. Based on scheduled settlement dates for these swaps, $5 million of this amount is
classified as other current assets in the accompanying balance sheet. The remaining $18 million is
classified as other long-term assets. In addition, the $23 million unrealized gain during the third
quarter of 2008 is included in change in fair value of other financial instruments in the
accompanying statement of operations. There were no cash settlements in the third quarter of 2008.
5. Debt
Senior Credit Facility
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 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. In August 2008, Devon secured an additional $150 million
of available credit under its Senior Credit Facility. The additional $150 million will mature on
April 7, 2013. This increases Devons total line of credit under its Senior Credit Facility to
$2.65 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 September 30, 2008, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at September 30, 2008, as calculated pursuant to the
terms of the agreement, was 15.4%.
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. As of November 5, 2008, Devons available capacity
under its Senior Credit Facility was approximately $2.4 billion. This available capacity is net
of $118 million of outstanding letters of credit and $137 million of outstanding commercial
paper borrowings as of November 5, 2008.
Short-Term Credit Facilities
Devon had a
$1.5 billion 364-day, syndicated, unsecured revolving senior credit facility. This
facility matured on August 5, 2008 and was not extended.
On November 5, 2008, Devon established a new $700 million 364-day, syndicated, unsecured
revolving senior credit facility (the
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Short-Term Facility). This new facility provides Devon with
incremental liquidity to support the retirement of maturing debentures
during 2008 and near-term capital expenditures. The Short-Term Facility also supports an
increase in Devons commercial paper program to $2.85 billion.
The Short-Term Facility matures on
November 3, 2009. On the maturity date, all amounts
outstanding will be due and payable at that time. Amounts borrowed under the Short-Term Facility
bear interest at various fixed rate options for periods of up to 12 months. Such rates are
generally based on LIBOR or the prime rate. The Short-Term Facility currently provides for an
annual facility fee of approximately $0.7 million that is payable quarterly in arrears.
The agreement governing the Short-Term Facility contains substantially the same covenants and
restrictions as Devons existing Senior Credit Facility, including a maximum allowed
debt-to-capitalization ratio of 65% as defined in the agreement.
As of
November 5, 2008, there were no amounts borrowed under the Short-Term Facility, and the
available capacity was $700 million.
Exchangeable Debentures
During 2008, virtually all holders of exchangeable debentures exercised their option to
exchange their debentures for shares of Chevron Corporation (Chevron) common stock owned by
Devon. The debentures matured on August 15, 2008. In lieu of delivering its shares of Chevron
common stock, Devon exercised its option to pay the exchanging debenture holders cash totaling $1.0
billion.
6. 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 September 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of September 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 |
|
$ |
125 |
|
|
$ |
125 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
124 |
|
Investment in Chevron common stock |
|
$ |
1,170 |
|
|
$ |
1,170 |
|
|
$ |
1,170 |
|
|
$ |
|
|
|
$ |
|
|
Net oil and gas price swaps and collars |
|
$ |
152 |
|
|
$ |
152 |
|
|
$ |
|
|
|
$ |
152 |
|
|
$ |
|
|
Interest rate swaps |
|
$ |
23 |
|
|
$ |
23 |
|
|
$ |
|
|
|
$ |
23 |
|
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,571 |
) |
|
$ |
(1,571 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,571 |
) |
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 September 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 September 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 September 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, the collection of all
accrued interest to date and continued receipts of principal at par. 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 September 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 nine months of 2008 (in millions).
|
|
|
|
|
Beginning balance |
|
$ |
|
|
Transfers from Level 1 to Level 3 |
|
|
129 |
|
Redemptions of principal |
|
|
(5 |
) |
|
|
|
|
Ending balance |
|
$ |
124 |
|
|
|
|
|
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 3.
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. 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 nine-month periods ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Nine Months |
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
10 |
|
|
$ |
8 |
|
|
$ |
30 |
|
|
$ |
23 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
14 |
|
|
|
11 |
|
|
|
42 |
|
|
|
33 |
|
|
|
2 |
|
|
|
1 |
|
|
|
6 |
|
|
|
3 |
|
Expected return on plan assets |
|
|
(13 |
) |
|
|
(12 |
) |
|
|
(39 |
) |
|
|
(36 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
actuarial loss and prior service cost |
|
|
4 |
|
|
|
3 |
|
|
|
12 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
|
15 |
|
|
|
10 |
|
|
|
45 |
|
|
|
30 |
|
|
|
2 |
|
|
|
1 |
|
|
|
6 |
|
|
|
3 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial
loss and prior service cost in net periodic benefit cost |
|
|
(4 |
) |
|
|
(4 |
) |
|
|
(12 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized |
|
$ |
11 |
|
|
$ |
6 |
|
|
$ |
33 |
|
|
$ |
18 |
|
|
$ |
2 |
|
|
$ |
1 |
|
|
$ |
6 |
|
|
$ |
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon previously disclosed in its financial statements for the year ended December 31, 2007,
that it expected to contribute $8 million to its defined benefit pension plans and $6 million to
its defined benefit postretirement plans in 2008. Subsequent to the end of 2007, Devon raised its
estimated 2008 contributions to its pension plans to $24 million. As of September 30, 2008, Devon
had contributed $14 million to the pension plans and $5 million to the postretirement plans.
Devons assets related to its pension plans have been adversely impacted by the performance of
the equity markets in recent months, especially since September 30, 2008. Losses incurred on these
investments will likely cause Devon to contribute more to its pension plans in 2009 than what would
otherwise have been expected. Such losses will also likely cause an increase in Devons pension
expense in 2009. However, the amounts of additional contributions and pension expense are not
expected to have a material impact on Devons liquidity or results of operations.
8. 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 nine months of 2008, Devon repurchased 6.5 million shares for $665 million,
or $102.56 per share, under programs approved by its Board of Directors. The 6.5 million shares
include 4.5 million shares that were repurchased under Devons 50 million share program and 2.0
million shares that were repurchased under Devons ongoing, annual stock repurchase program.
Dividends
Devon paid common stock dividends of $211 million (or a quarterly rate of $0.16 per share) and
$186 million (or a quarterly rate of $0.14 per share) in the first nine months of 2008 and 2007,
respectively. Devon paid preferred stock dividends of $5 million and
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
$7 million in the first nine months of 2008 and 2007, respectively. The decrease in the
preferred stock dividend is due to the redemption of the preferred stock in the second quarter of
2008.
9. 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. However,
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. The first phase
was scheduled to begin in August 2008, but the defendant settled prior to trial. The second phase
is 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.
On several occasions in 2007 and the first nine months of 2008, the U.S. House of
Representatives passed or attempted to pass legislation that would have required companies to pay
additional fees or renegotiate the 1998 and 1999 leases as a condition of securing future federal
leases. The legislation that was passed by the U.S. House of Representatives 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 September 30, 2008, approximately $44
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 $37 million accrued at September 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,
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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.
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 September
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. 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 included a standard, per-event deductible of $1 million for offshore losses as well as a
$15 million aggregate annual deductible.
Devon suffered insured damages in the third quarter of 2005 related to hurricanes that struck
the Gulf of Mexico. As of September 30, 2008, Devon had received $467 million in 2006 as a full
settlement of the amount due from its primary insurers and an additional $13 million in 2007 as a
full settlement of the amount due from certain of its secondary insurers. Devons claims under its
then existing insurance arrangements included both physical damages and business interruption
claims. As of September 30, 2008, $418 million of these proceeds had been utilized as reimbursement
of past repair costs and deductible amounts, and only $5 million is expected to be spent on future
repairs. The $57 million of excess recoveries to date were recorded as other income in the third
quarter of 2008. Devon expects to receive approximately $44 million of additional recoveries in the
fourth quarter of 2008. Such amount will be recorded as other income at the time it is received.
While Devon continues to negotiate with its secondary insurers, it may be forced to initiate
litigation against these insurers to recover the remaining amounts Devon believes it is entitled to
under the terms of its insurance coverage in 2005.
The policy underlying the insurance program terms described above expired on August 31, 2006.
Due to significant changes in the insurance marketplace, Devon no longer has coverage for damage
that may be caused by named windstorms from the Gulf of Mexico. As a result, Devons current
insurance program includes coverage for physical damage and business interruption but does not have
such coverage for damages or business interruption caused from named windstorms.
During the third quarter of 2008, Hurricanes Ike and Gustav damaged certain of Devons oil and
gas facilities and transportation systems in the Gulf of Mexico. These damages relate to both
production operations that will be repaired and restored and production operations that will not be
restored. These damages are uninsured losses because they resulted from named windstorms.
For the damaged facilities and transportation systems for which Devon intends to resume
operations after repairs have been made, a $14 million loss was recognized in the third quarter of
2008. This loss is included in lease operating expenses in the accompanying statement of
operations.
The facilities for which Devon will not restore production operations consist of certain
platforms that were completely destroyed.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Devon has begun performing asset retirement activities
associated with the destroyed platforms and related wells. The time and effort required to complete
such activities is expected to be significant due to the hazardous conditions created by the
hurricanes. As a result,
the estimated costs to complete the asset retirement activities are $82 million higher than
Devons previously estimated asset retirement obligation related to the destroyed platforms and
related wells. Therefore, in the third quarter of 2008, Devon increased its asset retirement
obligation by $82 million with a corresponding increase to oil and gas property and equipment in
the accompanying balance sheet. Based on the projected timing of the retirement activities, half of
this asset retirement obligation increase was recorded to the current portion and half was recorded
to the long-term portion.
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.
10. 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.
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.
With the approval of Devons Compensation Committee, Devon granted 0.4 million restricted
stock awards and units to certain non-executive employees in the third quarter of 2008. The grant
date fair value was $39 million based upon a grant price of $87.33 per share.
11. Change in Fair Value of Other Financial Instruments
The components of the change in fair value of other financial instruments include the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Losses (gains) from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron common stock |
|
$ |
236 |
|
|
$ |
(133 |
) |
|
$ |
154 |
|
|
$ |
(285 |
) |
Option embedded in exchangeable debentures |
|
|
(167 |
) |
|
|
111 |
|
|
|
(109 |
) |
|
|
255 |
|
Interest rate swaps |
|
|
(23 |
) |
|
|
|
|
|
|
(23 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
46 |
|
|
$ |
(22 |
) |
|
$ |
22 |
|
|
$ |
(31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
12. Income Taxes
During the first nine months of 2008, Devon repatriated $2.3 billion in earnings from certain
foreign subsidiaries to the United States. Devon also expects to repatriate approximately $0.4
billion in earnings from certain foreign subsidiaries to the United States during the last three
months of 2008. Subsequent to these repatriations, Devon does not expect to repatriate similar
earnings from its
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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 completed and planned repatriations, as well as the 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.
13. 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 third quarter of 2008, Devon sold its assets and terminated its operations in Cote
dIvoire. As a result of this sale, Devon recognized a gain of $83 million ($101 million after tax)
in the third quarter of 2008 from proceeds of $205 million ($163 million net of purchase price
adjustments).
With the completion of the Cote dIvoire transaction, Devon has divested all its oil and gas
producing properties in Africa. The Africa divestitures have generated just over $3.0 billion of
sales proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2
billion and generated after-tax gains of $0.8 billion.
Financial Statement Information
Operating revenues related to Devons discontinued operations totaled $17 million and $206
million in the three months ended September 30, 2008 and September 30, 2007 and $349 million and
$596 million in the nine months ended September 30, 2008 and 2007, respectively. These amounts do
not include the divestiture gains discussed in the previous section.
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The following table presents the main classes of assets and liabilities associated with
Devons discontinued operations as of September 30, 2008 and December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008 |
|
|
December 31, 2007 |
|
|
|
(In millions) |
|
Assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
3 |
|
|
$ |
9 |
|
Accounts receivable |
|
|
|
|
|
|
83 |
|
Other current assets |
|
|
85 |
|
|
|
28 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
88 |
|
|
$ |
120 |
|
|
|
|
|
|
|
|
Long-term assets property and equipment, net of
accumulated depreciation, depletion and amortization |
|
$ |
19 |
|
|
$ |
1,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable trade |
|
$ |
1 |
|
|
$ |
23 |
|
Revenues and royalties due to others |
|
|
|
|
|
|
11 |
|
Income taxes payable |
|
|
6 |
|
|
|
100 |
|
Current portion of asset retirement obligation |
|
|
|
|
|
|
9 |
|
Accrued expenses and other current liabilities |
|
|
5 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
12 |
|
|
$ |
145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
|
|
|
$ |
35 |
|
Deferred income taxes |
|
|
1 |
|
|
|
366 |
|
Other long-term liabilities |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
1 |
|
|
$ |
404 |
|
|
|
|
|
|
|
|
14. 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 nine-month periods ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
|
Weighted |
|
|
|
|
|
|
Earnings |
|
|
Average |
|
|
|
|
|
|
Applicable to |
|
|
Common |
|
|
Net |
|
|
|
Common |
|
|
Shares |
|
|
Earnings |
|
|
|
Stockholders |
|
|
Outstanding |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
$ |
2,509 |
|
|
|
442 |
|
|
$ |
5.67 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
2,509 |
|
|
|
446 |
|
|
$ |
5.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
644 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
642 |
|
|
|
445 |
|
|
$ |
1.45 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
642 |
|
|
|
450 |
|
|
$ |
1.43 |
|
|
|
|
|
|
|
|
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
|
Weighted |
|
|
|
|
|
|
Earnings |
|
|
Average |
|
|
|
|
|
|
Applicable to |
|
|
Common |
|
|
Net |
|
|
|
Common |
|
|
Shares |
|
|
Earnings |
|
|
|
Stockholders |
|
|
Outstanding |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Nine Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
3,754 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
3,749 |
|
|
|
444 |
|
|
$ |
8.44 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
3,749 |
|
|
|
448 |
|
|
$ |
8.36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
2,042 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
2,035 |
|
|
|
445 |
|
|
$ |
4.57 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
2,035 |
|
|
|
450 |
|
|
$ |
4.52 |
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. During the three-month and nine-month periods
ended September 30, 2008, 1.6 million shares and 1.5 million shares, respectively, were excluded
from the diluted earnings per share calculations. During the three-month and nine-month periods
ended September 30, 2007, 2.1 million shares and 4.0 million shares, respectively, were excluded
from the diluted earnings per share calculations.
15. 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 September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
1,775 |
|
|
$ |
963 |
|
|
$ |
681 |
|
|
$ |
3,419 |
|
Property and equipment, net of accumulated
depreciation, depletion and amortization |
|
|
21,230 |
|
|
|
8,786 |
|
|
|
1,434 |
|
|
|
31,450 |
|
Goodwill |
|
|
3,050 |
|
|
|
2,848 |
|
|
|
68 |
|
|
|
5,966 |
|
Other long-term assets |
|
|
1,527 |
|
|
|
62 |
|
|
|
231 |
|
|
|
1,820 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
27,582 |
|
|
$ |
12,659 |
|
|
$ |
2,414 |
|
|
$ |
42,655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
2,098 |
|
|
$ |
525 |
|
|
$ |
436 |
|
|
$ |
3,059 |
|
Long-term debt |
|
|
1,859 |
|
|
|
2,978 |
|
|
|
|
|
|
|
4,837 |
|
Asset retirement obligation, long-term |
|
|
725 |
|
|
|
635 |
|
|
|
96 |
|
|
|
1,456 |
|
Other long-term liabilities |
|
|
785 |
|
|
|
43 |
|
|
|
6 |
|
|
|
834 |
|
Deferred income taxes |
|
|
5,049 |
|
|
|
2,062 |
|
|
|
68 |
|
|
|
7,179 |
|
Stockholders equity |
|
|
17,066 |
|
|
|
6,416 |
|
|
|
1,808 |
|
|
|
25,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
27,582 |
|
|
$ |
12,659 |
|
|
$ |
2,414 |
|
|
$ |
42,655 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
467 |
|
|
$ |
507 |
|
|
$ |
322 |
|
|
$ |
1,296 |
|
Gas sales |
|
|
1,598 |
|
|
|
504 |
|
|
|
5 |
|
|
|
2,107 |
|
NGL sales |
|
|
288 |
|
|
|
74 |
|
|
|
|
|
|
|
362 |
|
Net gain on oil and gas derivative financial instruments |
|
|
1,592 |
|
|
|
|
|
|
|
|
|
|
|
1,592 |
|
Marketing and midstream revenues |
|
|
607 |
|
|
|
14 |
|
|
|
|
|
|
|
621 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
4,552 |
|
|
|
1,099 |
|
|
|
327 |
|
|
|
5,978 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
318 |
|
|
|
217 |
|
|
|
56 |
|
|
|
591 |
|
Production taxes |
|
|
87 |
|
|
|
1 |
|
|
|
64 |
|
|
|
152 |
|
Marketing and midstream operating costs and expenses |
|
|
447 |
|
|
|
5 |
|
|
|
|
|
|
|
452 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
505 |
|
|
|
224 |
|
|
|
52 |
|
|
|
781 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
60 |
|
|
|
7 |
|
|
|
|
|
|
|
67 |
|
Accretion of asset retirement obligation |
|
|
11 |
|
|
|
10 |
|
|
|
1 |
|
|
|
22 |
|
General and administrative expenses |
|
|
114 |
|
|
|
31 |
|
|
|
1 |
|
|
|
146 |
|
Interest expense |
|
|
15 |
|
|
|
54 |
|
|
|
|
|
|
|
69 |
|
Change in fair value of other financial instruments |
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
46 |
|
Other income, net |
|
|
(75 |
) |
|
|
(7 |
) |
|
|
(1 |
) |
|
|
(83 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,528 |
|
|
|
542 |
|
|
|
173 |
|
|
|
2,243 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax expense |
|
|
3,024 |
|
|
|
557 |
|
|
|
154 |
|
|
|
3,735 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
83 |
|
|
|
85 |
|
|
|
58 |
|
|
|
226 |
|
Deferred |
|
|
946 |
|
|
|
74 |
|
|
|
(20 |
) |
|
|
1,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
1,029 |
|
|
|
159 |
|
|
|
38 |
|
|
|
1,226 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
1,995 |
|
|
|
398 |
|
|
|
116 |
|
|
|
2,509 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
benefit |
|
|
|
|
|
|
|
|
|
|
93 |
|
|
|
93 |
|
Income tax benefit |
|
|
|
|
|
|
|
|
|
|
(16 |
) |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
109 |
|
|
|
109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
1,995 |
|
|
$ |
398 |
|
|
$ |
225 |
|
|
$ |
2,618 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
1,717 |
|
|
$ |
508 |
|
|
$ |
132 |
|
|
$ |
2,357 |
|
Revision of future ARO |
|
|
82 |
|
|
|
|
|
|
|
|
|
|
|
82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,799 |
|
|
$ |
508 |
|
|
$ |
132 |
|
|
$ |
2,439 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
359 |
|
|
$ |
224 |
|
|
$ |
322 |
|
|
$ |
905 |
|
Gas sales |
|
|
860 |
|
|
|
312 |
|
|
|
3 |
|
|
|
1,175 |
|
NGL sales |
|
|
196 |
|
|
|
46 |
|
|
|
|
|
|
|
242 |
|
Net gain on oil and gas derivative financial instruments |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
Marketing and midstream revenues |
|
|
421 |
|
|
|
13 |
|
|
|
|
|
|
|
434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,843 |
|
|
|
595 |
|
|
|
325 |
|
|
|
2,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
247 |
|
|
|
177 |
|
|
|
33 |
|
|
|
457 |
|
Production taxes |
|
|
50 |
|
|
|
1 |
|
|
|
34 |
|
|
|
85 |
|
Marketing and midstream operating costs and expenses |
|
|
296 |
|
|
|
5 |
|
|
|
|
|
|
|
301 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
457 |
|
|
|
193 |
|
|
|
55 |
|
|
|
705 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
45 |
|
|
|
5 |
|
|
|
1 |
|
|
|
51 |
|
Accretion of asset retirement obligation |
|
|
10 |
|
|
|
8 |
|
|
|
1 |
|
|
|
19 |
|
General and administrative expenses |
|
|
95 |
|
|
|
31 |
|
|
|
|
|
|
|
126 |
|
Interest expense |
|
|
58 |
|
|
|
50 |
|
|
|
|
|
|
|
108 |
|
Change in fair value of other financial instruments |
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
(22 |
) |
Other income, net |
|
|
(10 |
) |
|
|
(6 |
) |
|
|
(12 |
) |
|
|
(28 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,226 |
|
|
|
464 |
|
|
|
112 |
|
|
|
1,802 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax expense |
|
|
617 |
|
|
|
131 |
|
|
|
213 |
|
|
|
961 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(2 |
) |
|
|
40 |
|
|
|
58 |
|
|
|
96 |
|
Deferred |
|
|
215 |
|
|
|
8 |
|
|
|
(2 |
) |
|
|
221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
213 |
|
|
|
48 |
|
|
|
56 |
|
|
|
317 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
404 |
|
|
|
83 |
|
|
|
157 |
|
|
|
644 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
177 |
|
|
|
177 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
86 |
|
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
91 |
|
|
|
91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
404 |
|
|
|
83 |
|
|
|
248 |
|
|
|
735 |
|
Preferred stock dividends |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
402 |
|
|
$ |
83 |
|
|
$ |
248 |
|
|
$ |
733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,182 |
|
|
$ |
291 |
|
|
$ |
114 |
|
|
$ |
1,587 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Nine Months Ended September 30, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
1,476 |
|
|
$ |
1,345 |
|
|
$ |
1,180 |
|
|
$ |
4,001 |
|
Gas sales |
|
|
4,522 |
|
|
|
1,410 |
|
|
|
15 |
|
|
|
5,947 |
|
NGL sales |
|
|
859 |
|
|
|
210 |
|
|
|
|
|
|
|
1,069 |
|
Net loss on oil and gas derivative financial instruments |
|
|
(411 |
) |
|
|
|
|
|
|
|
|
|
|
(411 |
) |
Marketing and midstream revenues |
|
|
1,856 |
|
|
|
39 |
|
|
|
|
|
|
|
1,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
8,302 |
|
|
|
3,004 |
|
|
|
1,195 |
|
|
|
12,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
863 |
|
|
|
622 |
|
|
|
149 |
|
|
|
1,634 |
|
Production taxes |
|
|
270 |
|
|
|
3 |
|
|
|
189 |
|
|
|
462 |
|
Marketing and midstream operating costs and expenses |
|
|
1,334 |
|
|
|
15 |
|
|
|
|
|
|
|
1,349 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
1,446 |
|
|
|
662 |
|
|
|
172 |
|
|
|
2,280 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
165 |
|
|
|
20 |
|
|
|
1 |
|
|
|
186 |
|
Accretion of asset retirement obligation |
|
|
32 |
|
|
|
30 |
|
|
|
4 |
|
|
|
66 |
|
General and administrative expenses |
|
|
373 |
|
|
|
99 |
|
|
|
2 |
|
|
|
474 |
|
Interest expense |
|
|
103 |
|
|
|
158 |
|
|
|
|
|
|
|
261 |
|
Change in fair value of other financial instruments |
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
22 |
|
Other income, net |
|
|
(92 |
) |
|
|
(12 |
) |
|
|
(17 |
) |
|
|
(121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
4,516 |
|
|
|
1,597 |
|
|
|
500 |
|
|
|
6,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax expense |
|
|
3,786 |
|
|
|
1,407 |
|
|
|
695 |
|
|
|
5,888 |
|
Income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
428 |
|
|
|
149 |
|
|
|
166 |
|
|
|
743 |
|
Deferred |
|
|
1,159 |
|
|
|
226 |
|
|
|
6 |
|
|
|
1,391 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
1,587 |
|
|
|
375 |
|
|
|
172 |
|
|
|
2,134 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
2,199 |
|
|
|
1,032 |
|
|
|
523 |
|
|
|
3,754 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
1,133 |
|
|
|
1,133 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
219 |
|
|
|
219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
914 |
|
|
|
914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
2,199 |
|
|
|
1,032 |
|
|
|
1,437 |
|
|
|
4,668 |
|
Preferred stock dividends |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
2,194 |
|
|
$ |
1,032 |
|
|
$ |
1,437 |
|
|
$ |
4,663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
4,682 |
|
|
$ |
1,206 |
|
|
$ |
433 |
|
|
$ |
6,321 |
|
Revision of future ARO |
|
|
152 |
|
|
|
73 |
|
|
|
19 |
|
|
|
244 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
4,834 |
|
|
$ |
1,279 |
|
|
$ |
452 |
|
|
$ |
6,565 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Nine Months Ended September 30, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
898 |
|
|
$ |
562 |
|
|
$ |
1,001 |
|
|
$ |
2,461 |
|
Gas sales |
|
|
2,732 |
|
|
|
1,048 |
|
|
|
7 |
|
|
|
3,787 |
|
NGL sales |
|
|
509 |
|
|
|
134 |
|
|
|
|
|
|
|
643 |
|
Net loss on oil and gas derivative financial instruments |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Marketing and midstream revenues |
|
|
1,244 |
|
|
|
29 |
|
|
|
|
|
|
|
1,273 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
5,384 |
|
|
|
1,773 |
|
|
|
1,008 |
|
|
|
8,165 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
751 |
|
|
|
460 |
|
|
|
115 |
|
|
|
1,326 |
|
Production taxes |
|
|
165 |
|
|
|
3 |
|
|
|
87 |
|
|
|
255 |
|
Marketing and midstream operating costs and expenses |
|
|
900 |
|
|
|
12 |
|
|
|
|
|
|
|
912 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
1,230 |
|
|
|
535 |
|
|
|
172 |
|
|
|
1,937 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
130 |
|
|
|
15 |
|
|
|
1 |
|
|
|
146 |
|
Accretion of asset retirement obligation |
|
|
29 |
|
|
|
23 |
|
|
|
3 |
|
|
|
55 |
|
General and administrative expenses |
|
|
278 |
|
|
|
83 |
|
|
|
(3 |
) |
|
|
358 |
|
Interest expense |
|
|
174 |
|
|
|
151 |
|
|
|
|
|
|
|
325 |
|
Change in fair value of other financial instruments |
|
|
(30 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(31 |
) |
Other income, net |
|
|
(28 |
) |
|
|
(11 |
) |
|
|
(32 |
) |
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
3,599 |
|
|
|
1,270 |
|
|
|
343 |
|
|
|
5,212 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax
expense |
|
|
1,785 |
|
|
|
503 |
|
|
|
665 |
|
|
|
2,953 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
120 |
|
|
|
145 |
|
|
|
194 |
|
|
|
459 |
|
Deferred |
|
|
467 |
|
|
|
3 |
|
|
|
(18 |
) |
|
|
452 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
587 |
|
|
|
148 |
|
|
|
176 |
|
|
|
911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
1,198 |
|
|
|
355 |
|
|
|
489 |
|
|
|
2,042 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax
expense |
|
|
|
|
|
|
|
|
|
|
442 |
|
|
|
442 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
194 |
|
|
|
194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
248 |
|
|
|
248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
1,198 |
|
|
|
355 |
|
|
|
737 |
|
|
|
2,290 |
|
Preferred stock dividends |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
1,191 |
|
|
$ |
355 |
|
|
$ |
737 |
|
|
$ |
2,283 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
3,204 |
|
|
$ |
952 |
|
|
$ |
329 |
|
|
$ |
4,485 |
|
Revision of future ARO |
|
|
210 |
|
|
|
99 |
|
|
|
2 |
|
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
3,414 |
|
|
$ |
1,051 |
|
|
$ |
331 |
|
|
$ |
4,796 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion addresses material changes in our results of operations and capital
resources and uses for the three-month and nine-month periods ended September 30, 2008, compared to
the three-month and nine-month periods ended September 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.
Business Overview
During the third quarter and first nine months of 2008, we generated net earnings of $2.6
billion and $4.7 billion, respectively, or $5.87 and $10.40 per diluted share, representing
increases of 260% and 105% over the same periods of 2007. Additionally, net cash provided by
operating activities for the first nine months of 2008 climbed to a record amount of $8.2 billion,
representing a 60% increase over 2007. These increases in earnings and cash flow were largely
attributable to the following factors:
|
|
|
Production increased 3% and 6% in the third quarter and first nine months of 2008,
respectively. |
|
|
|
|
The combined realized price without hedges for oil, gas and NGLs increased 57% and 51%
in the third quarter and first nine months of 2008, respectively. |
|
|
|
|
Oil and gas hedges generated a net gain of $1.6 billion in the third quarter of 2008 and
a net loss of $411 million in the first nine months of 2008. Included in these amounts were
cash payments of $240 million and $551 million, respectively. |
|
|
|
|
Marketing and midstream operating profit increased 28% and 52% in the third quarter and
first nine months of 2008, respectively. |
|
|
|
|
Per unit operating costs rose 26% and 17% in the third quarter and first nine months of
2008, respectively. |
|
|
|
|
General and administrative expenses increased 17% and 33% in the third quarter and first
nine months of 2008, respectively. |
|
|
|
|
Cash spent on capital expenditures for oil and gas exploration and development
activities was $5.7 billion during the first nine months of 2008. |
In the third quarter of 2008, we sold our operations in Cote dIvoire, completing another sale
under our African divestiture program. The sales price was $205 million ($163 million net of
purchase price adjustments). As a result of this sale, we recognized an after-tax gain of $101
million in the third quarter of 2008.
With the completion of the Cote dIvoire transaction, we have divested all our oil and gas
producing properties in Africa, including Equatorial Guineathe largest individual transaction in
the divestiture program. The Africa divestitures have generated just over $3.0 billion of sales
proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2 billion and
generated after-tax gains of $0.8 billion. Also, in conjunction with these asset sales, we
repatriated an additional $2.3 billion of earnings from certain foreign subsidiaries to the United
States in the first nine months of 2008. We also expect to repatriate $0.4 billion from certain
foreign subsidiaries to the United States in the fourth quarter 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 2008, we fully
redeemed our exchangeable debentures for cash payments totaling $1.0 billion. We also repurchased
6.5 million common shares for $665 million and redeemed $150 million of preferred stock during the
first nine months of 2008.
Industry Overview and Outlook
As disclosed in our 2007 Annual Report on Form 10-K/A, our current and future earnings depend
largely on our ability to replace and grow oil and gas reserves, increase production and exert cost
discipline. We must also manage commodity pricing risks to achieve long-term success. Recently,
managing and reacting to the volatility of oil and natural gas prices has been an important part of
our strategy.
28
Oil and natural gas prices have reached historical high levels in recent years and during the
first half of 2008. These high prices have been a key factor in the oil and gas industry
experiencing cost increases that have exceeded general inflation trends. We are no different from
others in the industry in that we have been impacted by these cost increases. However, we have
continued to remain disciplined with regards to our operating costs and capital expenditures. We
have utilized the record operating cash flows generated by high commodity prices, along with
proceeds from our African divestitures, to, among other uses, repay outstanding debt. During 2007
and the first nine months of 2008, we repaid outstanding debt totaling $3.4 billion. During this
same period, we also repurchased $1.0 billion of our common stock and redeemed $150 million of
preferred stock.
As we exited the third quarter of 2008, oil and natural gas prices had declined sharply from
their recent record levels. In addition, recent problems in the credit markets, steep stock market
declines, financial institution failures and government bail-outs provide evidence of a weakening
United States and global economy. As a result of the market turmoil and price decreases, oil and
gas companies with high debt levels and lack of liquidity have been and will continue to be
negatively impacted.
However, we do not expect to be significantly impacted by these recent events. We are in a
financially-strong position due to our past strategies. We continue to have access to the
commercial paper market, and we had $3.1 billion of available capacity under our credit
facilities as of November 5, 2008. We also anticipate our operating cash flow and other capital
resources, if needed, will adequately fund our planned capital expenditures and other capital uses
over the near-term.
Results of Operations
Revenues
Oil, Gas and NGL Sales
The three-month and nine-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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
12 |
|
|
|
13 |
|
|
|
-10 |
% |
|
|
39 |
|
|
|
41 |
|
|
|
-4 |
% |
Gas (Bcf) |
|
|
239 |
|
|
|
223 |
|
|
|
+7 |
% |
|
|
692 |
|
|
|
637 |
|
|
|
+9 |
% |
NGLs (MMBbls) |
|
|
7 |
|
|
|
7 |
|
|
|
+5 |
% |
|
|
21 |
|
|
|
19 |
|
|
|
+10 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
58 |
|
|
|
57 |
|
|
|
+3 |
% |
|
|
175 |
|
|
|
166 |
|
|
|
+6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
106.95 |
|
|
$ |
67.41 |
|
|
|
+59 |
% |
|
$ |
101.42 |
|
|
$ |
59.88 |
|
|
|
+69 |
% |
Gas (Per Mcf) |
|
$ |
8.82 |
|
|
$ |
5.28 |
|
|
|
+67 |
% |
|
$ |
8.60 |
|
|
$ |
5.95 |
|
|
|
+45 |
% |
NGLs (Per Bbl) |
|
$ |
54.72 |
|
|
$ |
38.34 |
|
|
|
+43 |
% |
|
$ |
52.03 |
|
|
$ |
34.31 |
|
|
|
+52 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
64.29 |
|
|
$ |
40.86 |
|
|
|
+57 |
% |
|
$ |
62.84 |
|
|
$ |
41.52 |
|
|
|
+51 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
1,296 |
|
|
$ |
905 |
|
|
|
+43 |
% |
|
$ |
4,001 |
|
|
$ |
2,461 |
|
|
|
+63 |
% |
Gas sales |
|
|
2,107 |
|
|
|
1,175 |
|
|
|
+79 |
% |
|
|
5,947 |
|
|
|
3,787 |
|
|
|
+57 |
% |
NGL sales |
|
|
362 |
|
|
|
242 |
|
|
|
+50 |
% |
|
|
1,069 |
|
|
|
643 |
|
|
|
+66 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
3,765 |
|
|
$ |
2,322 |
|
|
|
+62 |
% |
|
$ |
11,017 |
|
|
$ |
6,891 |
|
|
|
+60 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic |
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
4 |
|
|
|
5 |
|
|
|
-20 |
% |
|
|
13 |
|
|
|
14 |
|
|
|
-7 |
% |
Gas (Bcf) |
|
|
185 |
|
|
|
164 |
|
|
|
+13 |
% |
|
|
532 |
|
|
|
465 |
|
|
|
+14 |
% |
NGLs (MMBbls) |
|
|
6 |
|
|
|
6 |
|
|
|
+5 |
% |
|
|
18 |
|
|
|
16 |
|
|
|
+13 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
40 |
|
|
|
38 |
|
|
|
+7 |
% |
|
|
119 |
|
|
|
107 |
|
|
|
+11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
118.70 |
|
|
$ |
73.19 |
|
|
|
+62 |
% |
|
$ |
111.94 |
|
|
$ |
63.01 |
|
|
|
+78 |
% |
Gas (Per Mcf) |
|
$ |
8.66 |
|
|
$ |
5.23 |
|
|
|
+65 |
% |
|
$ |
8.50 |
|
|
$ |
5.87 |
|
|
|
+45 |
% |
NGLs (Per Bbl) |
|
$ |
51.50 |
|
|
$ |
36.78 |
|
|
|
+40 |
% |
|
$ |
48.96 |
|
|
$ |
32.68 |
|
|
|
+50 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
58.38 |
|
|
$ |
37.62 |
|
|
|
+55 |
% |
|
$ |
57.43 |
|
|
$ |
38.55 |
|
|
|
+49 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
467 |
|
|
$ |
359 |
|
|
|
+30 |
% |
|
$ |
1,476 |
|
|
$ |
898 |
|
|
|
+64 |
% |
Gas sales |
|
|
1,598 |
|
|
|
860 |
|
|
|
+86 |
% |
|
|
4,522 |
|
|
|
2,732 |
|
|
|
+66 |
% |
NGL sales |
|
|
288 |
|
|
|
196 |
|
|
|
+47 |
% |
|
|
859 |
|
|
|
509 |
|
|
|
+69 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
2,353 |
|
|
$ |
1,415 |
|
|
|
+66 |
% |
|
$ |
6,857 |
|
|
$ |
4,139 |
|
|
|
+66 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
5 |
|
|
|
4 |
|
|
|
+30 |
% |
|
|
15 |
|
|
|
12 |
|
|
|
+32 |
% |
Gas (Bcf) |
|
|
54 |
|
|
|
59 |
|
|
|
-7 |
% |
|
|
159 |
|
|
|
171 |
|
|
|
-7 |
% |
NGLs (MMBbls) |
|
|
1 |
|
|
|
1 |
|
|
|
5 |
% |
|
|
3 |
|
|
|
3 |
|
|
|
-5 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
15 |
|
|
|
15 |
|
|
|
+4 |
% |
|
|
45 |
|
|
|
43 |
|
|
|
+4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
92.98 |
|
|
$ |
53.40 |
|
|
|
+74 |
% |
|
$ |
87.28 |
|
|
$ |
48.01 |
|
|
|
+82 |
% |
Gas (Per Mcf) |
|
$ |
9.36 |
|
|
$ |
5.40 |
|
|
|
+73 |
% |
|
$ |
8.90 |
|
|
$ |
6.16 |
|
|
|
+45 |
% |
NGLs (Per Bbl) |
|
$ |
72.19 |
|
|
$ |
46.77 |
|
|
|
+54 |
% |
|
$ |
70.00 |
|
|
$ |
42.36 |
|
|
|
+65 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
70.24 |
|
|
$ |
39.28 |
|
|
|
+79 |
% |
|
$ |
66.16 |
|
|
$ |
40.33 |
|
|
|
+64 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
507 |
|
|
$ |
224 |
|
|
|
+127 |
% |
|
$ |
1,345 |
|
|
$ |
562 |
|
|
|
+139 |
% |
Gas sales |
|
|
504 |
|
|
|
312 |
|
|
|
+61 |
% |
|
|
1,410 |
|
|
|
1,048 |
|
|
|
+35 |
% |
NGL sales |
|
|
74 |
|
|
|
46 |
|
|
|
+61 |
% |
|
|
210 |
|
|
|
134 |
|
|
|
+57 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
1,085 |
|
|
$ |
582 |
|
|
|
+86 |
% |
|
$ |
2,965 |
|
|
$ |
1,744 |
|
|
|
+70 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
3 |
|
|
|
4 |
|
|
|
-37 |
% |
|
|
11 |
|
|
|
15 |
|
|
|
-28 |
% |
Gas (Bcf) |
|
|
|
|
|
|
|
|
|
|
2 |
% |
|
|
1 |
|
|
|
1 |
|
|
|
+17 |
% |
NGLs (MMBbls) |
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
N/M |
|
Oil, Gas and NGLs (MMBoe)(1) |
|
|
3 |
|
|
|
4 |
|
|
|
-36 |
% |
|
|
11 |
|
|
|
16 |
|
|
|
-28 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
117.97 |
|
|
$ |
74.43 |
|
|
|
+58 |
% |
|
$ |
108.73 |
|
|
$ |
66.10 |
|
|
|
+64 |
% |
Gas (Per Mcf) |
|
$ |
10.72 |
|
|
$ |
6.61 |
|
|
|
+62 |
% |
|
$ |
9.95 |
|
|
$ |
5.73 |
|
|
|
+74 |
% |
NGLs (Per Bbl) |
|
$ |
|
|
|
$ |
|
|
|
|
N/M |
|
|
$ |
|
|
|
$ |
|
|
|
|
N/M |
|
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
116.35 |
|
|
$ |
73.77 |
|
|
|
+58 |
% |
|
$ |
107.63 |
|
|
$ |
65.66 |
|
|
|
+64 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
322 |
|
|
$ |
322 |
|
|
|
+0 |
% |
|
$ |
1,180 |
|
|
$ |
1,001 |
|
|
|
+18 |
% |
Gas sales |
|
|
5 |
|
|
|
3 |
|
|
|
+66 |
% |
|
|
15 |
|
|
|
7 |
|
|
|
+103 |
% |
NGL sales |
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
327 |
|
|
$ |
325 |
|
|
|
+0 |
% |
|
$ |
1,195 |
|
|
$ |
1,008 |
|
|
|
+18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
The volume and price changes in the tables above caused the following changes to our oil, gas
and NGL sales between the three months ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2007 sales |
|
$ |
905 |
|
|
$ |
1,175 |
|
|
$ |
242 |
|
|
$ |
2,322 |
|
Changes due to volumes |
|
|
(88 |
) |
|
|
87 |
|
|
|
12 |
|
|
|
11 |
|
Changes due to prices |
|
|
479 |
|
|
|
845 |
|
|
|
108 |
|
|
|
1,432 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales |
|
$ |
1,296 |
|
|
$ |
2,107 |
|
|
$ |
362 |
|
|
$ |
3,765 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The volume and price changes in the tables above caused the following changes to our oil, gas
and NGL sales between the nine months ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2007 sales |
|
$ |
2,461 |
|
|
$ |
3,787 |
|
|
$ |
643 |
|
|
$ |
6,891 |
|
Changes due to volumes |
|
|
(99 |
) |
|
|
328 |
|
|
|
62 |
|
|
|
291 |
|
Changes due to prices |
|
|
1,639 |
|
|
|
1,832 |
|
|
|
364 |
|
|
|
3,835 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales |
|
$ |
4,001 |
|
|
$ |
5,947 |
|
|
$ |
1,069 |
|
|
$ |
11,017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales decreased $88 million in the third quarter of 2008 due to a one million barrel, or
10%, decrease in production. Our International production decreased approximately one million
barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. We
also deferred 0.4 million barrels of oil production during the third quarter of 2008 as the result
of the effects of Hurricanes Ike and Gustav. These decreases were partially offset by additional
production resulting from increased development activity at our Jackfish and Lloydminster areas in
Canada.
31
Oil sales increased $479 million in the third quarter of 2008 as a result of a 59% increase in
our realized price without hedges. The average NYMEX West Texas Intermediate index price increased
58% during the same time period, accounting for the majority of the increase.
Oil sales decreased $99 million in the first nine months of 2008 due to a two million barrel,
or 4%, decrease in production. Our International production decreased approximately four million
barrels due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. We
also deferred 0.4 million barrels of oil production due to hurricanes. These decreases were
partially offset by additional production resulting from increased development activity at our
Jackfish and Lloydminster areas in Canada.
Oil sales increased $1.6 billion in the first nine months of 2008 as a result of a 69%
increase in our realized price without hedges. The average NYMEX West Texas Intermediate index
price increased 72% during the same time period, accounting for the majority of the increase.
Gas Sales
A 16 Bcf, or 7%, increase in production during the third quarter of 2008 caused gas sales to
increase by $87 million. Our drilling and development program in the Barnett Shale field in north
Texas contributed 23 Bcf to the gas production increase. We also deferred 5 Bcf of gas production
in the third quarter of 2008 due to Hurricanes Ike and Gustav. This net 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 $845 million during the third quarter of 2008 as a result of a 67%
increase in our realized price without hedges. This increase was largely due to increases in the
regional index prices upon which our gas sales are based.
A 55 Bcf, or 9%, increase in production during the first nine months of 2008 caused gas sales
to increase by $328 million. Our drilling and development program in the Barnett Shale field in
north Texas contributed 64 Bcf to the gas production increase. We also deferred 5 Bcf of gas
production due to hurricanes. This net 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 $1.8 billion during the first nine months of 2008 as a result of a 45%
increase in our realized price without hedges. This increase was largely due to increases in the
regional index prices upon which our gas sales are based.
Net Gain (Loss) on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated with our oil and gas hedges for
the third quarter and first nine months of 2008 and 2007. The first table presents the cash
settlements and unrealized gains and losses recognized as components of our revenues. The
subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash
settlements for the third quarter and first nine months of 2008 and 2007. The prices do not include
the effects of unrealized gains and losses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
(115 |
) |
|
$ |
14 |
|
|
$ |
(276 |
) |
|
$ |
29 |
|
Gas price collars |
|
|
(125 |
) |
|
|
|
|
|
|
(275 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received |
|
|
(240 |
) |
|
|
14 |
|
|
|
(551 |
) |
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
645 |
|
|
|
(7 |
) |
|
|
27 |
|
|
|
(26 |
) |
Gas price collars |
|
|
1,142 |
|
|
|
|
|
|
|
114 |
|
|
|
(4 |
) |
Oil price collars |
|
|
45 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) on fair value changes |
|
|
1,832 |
|
|
|
(7 |
) |
|
|
140 |
|
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net gain (loss) on oil and gas derivative financial instruments |
|
$ |
1,592 |
|
|
$ |
7 |
|
|
$ |
(411 |
) |
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2008 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
106.95 |
|
|
$ |
8.82 |
|
|
$ |
54.72 |
|
|
$ |
64.29 |
|
Cash settlements of hedges |
|
|
(0.01 |
) |
|
|
(1.01 |
) |
|
|
|
|
|
|
(4.10 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
106.94 |
|
|
$ |
7.81 |
|
|
$ |
54.72 |
|
|
$ |
60.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2007 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
67.41 |
|
|
$ |
5.28 |
|
|
$ |
38.34 |
|
|
$ |
40.86 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.06 |
|
|
|
|
|
|
|
0.24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
67.41 |
|
|
$ |
5.34 |
|
|
$ |
38.34 |
|
|
$ |
41.10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2008 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
101.42 |
|
|
$ |
8.60 |
|
|
$ |
52.03 |
|
|
$ |
62.84 |
|
Cash settlements of hedges |
|
|
|
|
|
|
(0.80 |
) |
|
|
|
|
|
|
(3.15 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
101.42 |
|
|
$ |
7.80 |
|
|
$ |
52.03 |
|
|
$ |
59.69 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2007 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
59.88 |
|
|
$ |
5.95 |
|
|
$ |
34.31 |
|
|
$ |
41.52 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.05 |
|
|
|
|
|
|
|
0.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
59.88 |
|
|
$ |
6.00 |
|
|
$ |
34.31 |
|
|
$ |
41.71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
During the third quarter and first nine months of 2008, we paid $240 million, or $1.01 per
Mcf, and $551 million, or $0.80 per Mcf, respectively, to counterparties to settle our gas price
swaps and collars. During the third quarter and nine months of 2007, we received $14 million, or
$0.06 per Mcf, and $31 million, or $0.05 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 September 30, 2008, a 10% increase in these forward curves would have
decreased our third quarter 2008 unrealized gain for our oil and gas derivative financial
instruments by approximately $130 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.
In spite of the recent turmoil in the financial markets, counterparty credit risk has not had
a significant effect on our cash flow calculations and commodity derivative valuations. This is
primarily the result of two factors. First, we have mitigated our exposure to any single
counterparty by contracting with numerous counterparties. Our commodity
33
derivative contracts are held with thirteen separate counterparties. Second, our derivative contracts
generally require cash collateral to be posted if either our or the counterpartys credit rating
falls below investment grade. The threshold for collateral posting decreases as the debt rating
falls further below investment grade. Such thresholds generally range from zero to $50 million for
the majority of our contracts. As of September 30, 2008, the credit ratings of all our
counterparties were investment grade.
The $1.8 billion unrealized gain in the third quarter of 2008 was primarily the result of
large fluctuations in the forward curves of the Inside FERC Henry Hub index. As a result of a
significant increase in the Inside FERC Henry Hub forward curve from our contract trade dates to
the end of the second quarter of 2008, we recognized a $1.7 billion unrealized loss during the
first half of 2008. During the third quarter of 2008, the Inside FERC Henry Hub forward curve
decreased considerably. As a result we recognized an unrealized gain of $1.8 billion, in effect,
reversing the unrealized loss recognized in the first half of 2008.
The $140 million unrealized gain in the first nine months of 2008 was primarily the result of
a decrease in the Inside FERC Henry Hub index subsequent to our trade dates.
During the third quarter and first nine months of 2007, we recognized unrealized losses
totaling $7 million and $30 million, respectively, related to our gas derivative instruments.
Marketing and Midstream Revenues and Operating Costs and Expenses
The details of the changes in marketing and midstream revenues, operating costs and expenses
and the resulting operating profit between the three months ended September 30, 2008 and 2007 and
the nine months ended September 30, 2008 and 2007 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Marketing and midstream ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
621 |
|
|
$ |
434 |
|
|
|
+43 |
% |
|
$ |
1,895 |
|
|
$ |
1,273 |
|
|
|
+49 |
% |
Operating costs and expenses |
|
|
452 |
|
|
|
301 |
|
|
|
+50 |
% |
|
|
1,349 |
|
|
|
912 |
|
|
|
+48 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
169 |
|
|
$ |
133 |
|
|
|
+28 |
% |
|
$ |
546 |
|
|
$ |
361 |
|
|
|
+52 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
During the third quarter of 2008, marketing and midstream revenues increased $187 million and
operating costs and expenses also increased $151 million, causing operating profit to increase $36
million. During the first nine months of 2008, marketing and midstream revenues increased $622
million and operating costs and expenses also increased $437 million, causing operating profit to
increase $185 million. Revenues and expenses increased during these periods primarily due to higher
natural gas and NGL prices, as well as higher gas pipeline throughput in the Barnett Shale.
34
Oil, Gas and NGL Production and Operating Expenses
The three-month and nine-month comparisons of oil, gas and NGL production and operating
expenses are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Production and operating expenses ($ in
millions): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
591 |
|
|
$ |
457 |
|
|
|
+29 |
% |
|
$ |
1,634 |
|
|
$ |
1,326 |
|
|
|
+23 |
% |
Production taxes |
|
|
152 |
|
|
|
85 |
|
|
|
+80 |
% |
|
|
462 |
|
|
|
255 |
|
|
|
+81 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses |
|
$ |
743 |
|
|
$ |
542 |
|
|
|
+37 |
% |
|
$ |
2,096 |
|
|
$ |
1,581 |
|
|
|
+33 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
10.09 |
|
|
$ |
8.04 |
|
|
|
+26 |
% |
|
$ |
9.32 |
|
|
$ |
7.99 |
|
|
|
+17 |
% |
Production taxes |
|
|
2.60 |
|
|
|
1.49 |
|
|
|
+74 |
% |
|
|
2.64 |
|
|
|
1.54 |
|
|
|
+71 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses per Boe |
|
$ |
12.69 |
|
|
$ |
9.53 |
|
|
|
+33 |
% |
|
$ |
11.96 |
|
|
$ |
9.53 |
|
|
|
+26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 $134 million in the third 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 $14 million due to our 3% growth in production. Additionally, LOE
increased $14 million due to damages of certain of our facilities and transportation systems that
were caused by Hurricane Ike in the third quarter of 2008. These hurricane damages also contributed
to the increase in LOE per Boe.
LOE increased $308 million in the first nine months 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 $75 million due to our 6% growth in production. Additionally, LOE
increased $14 million due to damages caused by Hurricane Ike. 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
September 30, 2008 and 2007 and the nine months ended September 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 |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
(In millions) |
|
2007 production taxes |
|
$ |
85 |
|
|
$ |
255 |
|
Change due to revenues |
|
|
52 |
|
|
|
153 |
|
Change due to rate |
|
|
15 |
|
|
|
54 |
|
|
|
|
|
|
|
|
2008 production taxes |
|
$ |
152 |
|
|
$ |
462 |
|
|
|
|
|
|
|
|
35
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 nine months ended September 30, 2008 and 2007 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, |
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Production volumes (MMBoe) |
|
|
58 |
|
|
|
57 |
|
|
|
+3 |
% |
|
|
175 |
|
|
|
166 |
|
|
|
+6 |
% |
DD&A rate ($ per Boe) |
|
$ |
13.34 |
|
|
$ |
12.41 |
|
|
|
+8 |
% |
|
$ |
13.01 |
|
|
$ |
11.67 |
|
|
|
+11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
781 |
|
|
$ |
705 |
|
|
|
+11 |
% |
|
$ |
2,280 |
|
|
$ |
1,937 |
|
|
|
+18 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 nine months ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
(In millions) |
|
2007 DD&A |
|
$ |
705 |
|
|
$ |
1,937 |
|
Change due to volumes |
|
|
21 |
|
|
|
109 |
|
Change due to rate |
|
|
55 |
|
|
|
234 |
|
|
|
|
|
|
|
|
2008 DD&A |
|
$ |
781 |
|
|
$ |
2,280 |
|
|
|
|
|
|
|
|
The 3% production increase during the third quarter of 2008 caused oil and gas property
related DD&A to increase $21 million. In addition, oil and gas property related DD&A increased $55
million due to an 8% 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 included the transfer of previously unproved costs to the depletable base as a
result of 2007 and 2008 drilling activities.
The 6% production increase during the first nine months of 2008 caused oil and gas property
related DD&A to increase $109 million. In addition, oil and gas property related DD&A increased
$234 million due to an 11% 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 included 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
nine-month periods ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
|
(In millions) |
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Gross G&A |
|
$ |
280 |
|
|
$ |
239 |
|
|
|
+17 |
% |
|
$ |
864 |
|
|
$ |
673 |
|
|
|
+29 |
% |
Capitalized G&A |
|
|
(99 |
) |
|
|
(84 |
) |
|
|
+18 |
% |
|
|
(298 |
) |
|
|
(230 |
) |
|
|
+30 |
% |
Reimbursed G&A |
|
|
(35 |
) |
|
|
(29 |
) |
|
|
+18 |
% |
|
|
(92 |
) |
|
|
(85 |
) |
|
|
+8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
146 |
|
|
$ |
126 |
|
|
|
+17 |
% |
|
$ |
474 |
|
|
$ |
358 |
|
|
|
+33 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
36
Gross G&A increased $41 million in the third 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.
The $15 million increase in capitalized G&A during the third quarter of 2008 is primarily due
to the higher employee compensation and benefits costs.
Gross G&A increased $191 million in the first nine months 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. 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 $68 million increase in capitalized G&A during the first nine months of 2008 was 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
nine-month periods ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
96 |
|
|
$ |
127 |
|
|
$ |
332 |
|
|
$ |
380 |
|
Capitalized interest |
|
|
(28 |
) |
|
|
(26 |
) |
|
|
(84 |
) |
|
|
(73 |
) |
Other |
|
|
1 |
|
|
|
7 |
|
|
|
13 |
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
69 |
|
|
$ |
108 |
|
|
$ |
261 |
|
|
$ |
325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding decreased during the third quarter of 2008 and the first
nine months of 2008 primarily due to a decrease in outstanding borrowings. The decrease in
borrowings resulted largely from the use of proceeds from our West African divestiture program and
cash flow from operations to repay all commercial paper and credit facility borrowings in the
second quarter of 2008. Additionally, we retired our exchangeable debentures during the third
quarter of 2008.
Change in Fair Value of Other 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 nine months ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Losses (gains) from: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chevron common stock |
|
$ |
236 |
|
|
$ |
(133 |
) |
|
$ |
154 |
|
|
$ |
(285 |
) |
Option embedded in exchangeable debentures |
|
|
(167 |
) |
|
|
111 |
|
|
|
(109 |
) |
|
|
255 |
|
Interest rate swaps |
|
|
(23 |
) |
|
|
|
|
|
|
(23 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
46 |
|
|
$ |
(22 |
) |
|
$ |
22 |
|
|
$ |
(31 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
37
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 was not actively traded in an established market. Therefore, we estimated
its fair value using quotes obtained from a broker for trades occurring near the valuation date.
Because the exchangeable debentures matured in August 2008, the embedded options recent fair value
changes largely coincided 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.
Since the exchangeable debentures were retired in August 2008, we will not recognize any future
gains or losses from the embedded option.
The loss on our investment in Chevron common stock was directly attributable to a $16.65
decrease in the price per share of Chevrons common stock during the third quarter of 2008. The
gain on the embedded option during the third quarter of 2008 was directly attributable to the
change in fair value of the Chevron common stock from July 1, 2008 to the maturity date of August
15, 2008. The gain on our investment in Chevron common stock and loss on the embedded option during
the third quarter of 2007 were directly attributable to a $9.34 increase in the price per share of
Chevrons common stock during the third quarter of 2007.
The loss on our investment in Chevron common stock and gain on the embedded option during the
first nine months of 2008 were primarily attributable to a $10.85 increase in the price per share
of Chevrons common stock during the first nine months of 2008. The gain on our investment in
Chevron common stock and loss on the embedded option during the first nine months of 2007 were
directly attributable to a $20.05 increase in the price per share of Chevrons common stock during
the first nine months of 2007.
We also recognize unrealized changes in the fair values of our interest rate swaps each
reporting period. We estimate the fair values of our interest rate swap financial instruments
primarily by using internal discounted cash flow calculations based upon forward interest-rate
yields. 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 interest
rate yields. We base our estimate of future yields upon our own internal model that utilizes
forward curves such as the LIBOR or the Federal Funds Rate provided by a third-party. Based on the
notional subject to the interest rate swaps at September 30, 2008, a 10% increase in these forward
curves would have decreased our third quarter 2008 unrealized gain for our interest rate swaps by
approximately $15 million.
In the third quarter of 2008, we recorded a $23 million unrealized gain as a result of changes
in interest rates subsequent to the trade date. There were no cash settlements in the third quarter
of 2008.
As previously discussed for our commodity derivative contracts, counterparty credit risk has
not had a significant effect on our cash flow calculations and interest rate derivative valuations.
Similar to our commodity derivative contracts, our interest rate derivative contracts are held with
five separate counterparties and have cash collateral posting requirements. Additionally, the
credit ratings of all our counterparties are investment grade as of September 30, 2008.
38
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 nine-month periods ended September 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 |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
Total income tax expense (In millions) |
|
$ |
1,226 |
|
|
$ |
317 |
|
|
$ |
2,134 |
|
|
$ |
911 |
|
|
U.S. statutory income tax rate |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
|
|
35 |
% |
Repatriations and tax policy election changes |
|
|
|
|
|
|
|
|
|
|
5 |
% |
|
|
|
|
Canadian statutory rate reductions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
%) |
Other, primarily taxation on foreign operations |
|
|
(2 |
%) |
|
|
(2 |
%) |
|
|
(4 |
%) |
|
|
(3 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate |
|
|
33 |
% |
|
|
33 |
% |
|
|
36 |
% |
|
|
31 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
For the nine months ended September 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. At the end of the second quarter of 2008, we also expected 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 rate would have been 31% for the first
nine months of 2008.
For the nine months ended September 30, 2007, our effective income tax rate was 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. Excluding the effect of the rate
reduction, our effective income tax rate would have been 32% for the first nine months of 2007.
These rates, as well as the rates for the third quarters of 2008 and 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.
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
nine months ended September 30, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Earnings from discontinued operations before income taxes |
|
$ |
93 |
|
|
$ |
177 |
|
|
$ |
1,133 |
|
|
$ |
442 |
|
Income tax expense (benefit) |
|
|
(16 |
) |
|
|
86 |
|
|
|
219 |
|
|
|
194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
$ |
109 |
|
|
$ |
91 |
|
|
$ |
914 |
|
|
$ |
248 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations increased $18 million in the third quarter of 2008. We
recognized a $101 million after-tax gain from the sale of our assets in Cote dIvoire in the third
quarter of 2008. This gain was largely offset by the effect of reduced earnings due to the sales of
our operations in Equatorial Guinea and Gabon in the second quarter
39
of 2008 and Egypt in the fourth quarter of 2007.
Earnings from discontinued operations increased $666 million in the first nine months of 2008.
We recognized after-tax gains totaling $748 million from the sale of our assets in Equatorial
Guinea, Gabon, Cote dIvoire and other countries in the second and third quarters of 2008. These
gains were largely offset by the effect of reduced earnings due to the sales of such operations.
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
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
8,079 |
|
|
$ |
4,739 |
|
Net credit facility borrowings |
|
|
|
|
|
|
400 |
|
Sales of property and equipment |
|
|
116 |
|
|
|
39 |
|
Stock option exercises |
|
|
109 |
|
|
|
71 |
|
Net sales of short-term investments |
|
|
247 |
|
|
|
233 |
|
Cash received from discontinued operations |
|
|
1,898 |
|
|
|
|
|
Other |
|
|
58 |
|
|
|
20 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
10,507 |
|
|
|
5,502 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(6,179 |
) |
|
|
(4,477 |
) |
Net commercial paper repayments |
|
|
(1,004 |
) |
|
|
(129 |
) |
Net repayments of debt |
|
|
(2,481 |
) |
|
|
(166 |
) |
Repurchases of common stock |
|
|
(665 |
) |
|
|
(133 |
) |
Redemption of preferred stock |
|
|
(150 |
) |
|
|
|
|
Dividends |
|
|
(216 |
) |
|
|
(193 |
) |
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(10,695 |
) |
|
|
(5,098 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) from continuing operations |
|
|
(188 |
) |
|
|
404 |
|
Increase from discontinued operations, net of
distributions to continuing operations
|
|
|
58 |
|
|
|
217 |
|
Effect of foreign exchange rates |
|
|
(47 |
) |
|
|
44 |
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
|
$ |
(177 |
) |
|
$ |
665 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
1,196 |
|
|
$ |
1,421 |
|
|
|
|
|
|
|
|
Short-term investments at end of period |
|
$ |
1 |
|
|
$ |
341 |
|
|
|
|
|
|
|
|
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 nine months 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 nine months of 2008 and 2007, our operating cash flow was sufficient to fund
our capital expenditures.
40
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 $247 million.
During 2007, we reduced our short-term investment balances by $233 million and utilized $105
million of net borrowings from our unsecured revolving line of credit to supplement our operating
cash flow and fund debt repayments.
In 2008, another significant source of cash has been the proceeds from our African divestiture
program. In the second and third quarters of 2008, we received $2.6 billion in proceeds ($1.9
billion net of income taxes and purchase price adjustments) from 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 $2.3
billion of earnings from certain foreign subsidiaries to the United States in the first nine months
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,
redemptions of preferred stock and dividends on common and preferred stock.
Capital Expenditures
Following are the components of our capital expenditures for the first nine months of 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
Nine Months |
|
|
|
Ended September 30, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
3,381 |
|
|
$ |
2,371 |
|
U.S. Offshore |
|
|
813 |
|
|
|
485 |
|
Canada |
|
|
1,137 |
|
|
|
928 |
|
International |
|
|
412 |
|
|
|
366 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
5,743 |
|
|
|
4,150 |
|
Midstream |
|
|
310 |
|
|
|
266 |
|
Other |
|
|
126 |
|
|
|
61 |
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
6,179 |
|
|
$ |
4,477 |
|
|
|
|
|
|
|
|
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 $5.7 billion and $4.2 billion in the first nine 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 $1.6 billion in the first nine
months of 2008. The higher expenditures primarily related to increased drilling activities in the
Barnett Shale, Gulf of Mexico and Carthage areas of the United States and the Lloydminster area of
Canada. Expenditures also increased due to inflationary pressure driven by increased competition
for field services.
Net Repayments of Debt
During the first nine months 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.
Also during the first nine months of 2008, virtually all holders of exchangeable debentures
exercised their option to exchange their debentures for shares of Chevron common stock owned by
Devon. The debentures matured on August 15, 2008. In lieu of delivering its shares of Chevron
common stock, Devon exercised its option to pay the exchanging
41
debenture holders cash totaling $1.0
billion. This amount included the retirement of debentures with a book value of $652
million and a $379 million reduction of the related embedded derivative options balance.
Repurchases of Common Stock
During the first nine months of 2008, we repurchased 6.5 million shares for $665 million, or
$102.56 per share. The 6.5 million shares include 4.5 million shares that were repurchased under
our 50 million share program and 2.0 million shares that were repurchased under our ongoing, annual
stock repurchase program.
During the first nine months of 2007, we repurchased 1.7 million shares at a cost of $133
million.
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 $211 million (or a quarterly rate of $0.16 per share) and $186
million (or a quarterly rate of $0.14 per share) in the first nine months of 2008 and 2007,
respectively. The higher dividend rate was the primary cause of the increase in common dividends.
Our preferred dividends were $5 million and $7 million in the first nine months of 2008 and 2007.
The decrease in the preferred dividends was due to the redemption of our preferred stock in the
second quarter of 2008.
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. Another available source of liquidity includes our cash on hand
which totaled $1.2 billion as of September 30, 2008. Additionally, the proceeds from the sales of
our operations in West Africa, including related repatriations of earnings from certain foreign
subsidiaries to the United States, has served as another major source of liquidity in 2008. During
the first nine months of 2008, we repatriated $2.3 billion in earnings. We expect to repatriate
approximately $0.4 billion during the last three months of 2008.
We currently estimate these capital resources will provide sufficient liquidity to fund our
planned uses of capital over the near-term. We are currently generating significant operating cash
flow that adequately funds our capital expenditures. Additionally, we have no short-term debt. We
also have approximately $3.1 billion of available capacity under our lines of credit.
The issuance of equity securities and long-term debt has occasionally over the years been a
source of capital and liquidity for us. The extraordinary conditions in the global financial and
capital markets have currently limited the availability of these resources. However, we do not
anticipate needing these types of capital resources for near-term liquidity needs.
Operating Cash Flow
Our operating cash flow increased 71% to a record high of $8.1 billion in the first nine
months 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.
Commodity Prices - 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
42
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.
Interest Rates - Our operating cash flow can also be sensitive to interest rate fluctuations.
As of September 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. Including the effects of these
swaps, the weighted-average interest rate related to our fixed-rate debt was 7.2% as of September
30, 2008. The key terms of these interest rate swaps are included in Item 3. Quantitative and
Qualitative Disclosures of Market Risk of this report.
Credit Losses - Our operating cash flow is also exposed to credit risk in a variety of ways.
We are exposed to the credit risk of the customers who purchase our oil, natural gas and NGL
production. We are also exposed to credit risk related to the collection of receivables from our
joint-interest partners for their proportionate share of expenditures made on projects we operate.
We are also exposed to the credit risk of counterparties to our derivative financial contracts as
discussed previously in this report.
The recent deterioration of the global financial and capital markets, combined with the drop
in oil and natural gas prices, has increased our credit risk exposure. However, we utilize a
variety of mechanisms to limit our exposure to the credit risks of our customers, partners and
counterparties. Such mechanisms include, under certain conditions, prepayment requirements for
commodity sales and collateral posting requirements in our existing derivative contracts. As a
result of these and other activities, we currently believe we have substantially mitigated the
credit risk effect on our operating cash flow.
Credit Lines
We have a five-year, syndicated, unsecured revolving line of credit (the Senior Credit
Facility). In August 2008, we added $150 million to our Senior Credit Facility, increasing the
total capacity to $2.65 billion.
On
November 5, 2008, we established a new $700 million 364-day, syndicated, unsecured
revolving senior credit facility (the Short-Term Facility). This new facility provides us with
incremental liquidity to support the retirement of maturing debentures during 2008 and near-term
capital expenditures. The Short-Term Facility also supports an increase in our commercial paper
program to $2.85 billion.
The Short-Term Facility matures on
November 3, 2009. On the maturity date, all amounts
outstanding will be due and payable at that time. Amounts borrowed under the Short-Term Facility
bear interest at various fixed rate options for periods of up to 12 months. Such rates are
generally based on LIBOR or the prime rate. The Short-Term Facility currently provides for an
annual facility fee of approximately $0.7 million that is payable quarterly in arrears.
The agreement governing the Short-Term Facility contains substantially the same covenants and
restrictions as Devons existing Senior Credit Facility, including a maximum allowed
debt-to-capitalization ratio of 65% as defined in the agreement.
43
The following schedule summarizes the capacity of our credit facilities by maturity date, as
well as our available capacity as of November 5, 2008.
|
|
|
|
|
Description |
|
Amount |
|
|
|
(In millions) |
|
Senior Credit Facility maturities: |
|
|
|
|
April 7, 2012 |
|
$ |
500 |
|
April 7, 2013 |
|
|
2,150 |
|
|
|
|
|
Senior Credit Facility total capacity |
|
|
2,650 |
|
Short-Term Facility total capacity |
|
|
700 |
|
|
|
|
|
Total credit facility capacity |
|
|
3,350 |
|
Less: |
|
|
|
|
Outstanding credit facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
137 |
|
Outstanding letters of credit |
|
|
118 |
|
|
|
|
|
Total credit facility available capacity |
|
$ |
3,095 |
|
|
|
|
|
The credit facilities contain 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 September 30, 2008, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at September 30, 2008, as calculated pursuant to the
terms of the agreement, was 15.4%.
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 October 31,
2008.
Property Divestitures
At the end of the third quarter of 2008, we had substantially completed our Africa divestiture
program. In the fourth quarter of 2007, we sold our assets in Egypt. In 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. In the third quarter of 2008, we
completed the sale of our assets in Cote dIvoire for $205 million ($163 million net of purchase
price adjustments). As a result of this sale, we recognized an after-tax gain of $101 million in
the third quarter of 2008.
With the completion of the Cote dIvoire transaction, we have divested all of our oil and gas
producing properties in Africa. The Africa divestitures have generated just over $3.0 billion of
sales proceeds. After income taxes and purchase price adjustments, such proceeds totaled $2.2
billion and generated after-tax gains of $0.8 billion. As planned, we have used these proceeds and
related repatriations to the United States to repay debt, repurchase common stock and redeem our
outstanding preferred stock during 2008.
Capital Expenditures
In August 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 $7.2 billion to $7.5 billion. Based upon current oil and natural gas price expectations
and the commodity price collars, swaps and fixed-price contracts we have in place, we anticipate
having adequate capital resources to fund our planned capital expenditures in the near-term.
Common Stock Repurchase Programs
Our Board of Directors approved an ongoing, annual stock repurchase program to mitigate
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
44
September 30, 2008, up to 2.8 million shares or $244 million can be repurchased under the ongoing,
annual repurchase program and up to 45.5 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 nine months of 2008, we reduced our auction rate securities holdings to $125
million as of September 30, 2008. However, since February 8, 2008, we have experienced difficulty
selling our securities due to the failure of the auction mechanism, which provided 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 September 30, 2008, issuers redeemed $27
million of our auction rate securities holdings at par. Additionally, our auction rate securities
holdings as of September 30, 2008, include approximately $1 million of securities that were called
at par value by the issuer and were repaid on October 1, 2008. These called securities continue to
be considered short-term investments as of September 30, 2008. However, based on continued auction
failures and the current market for our auction rate securities, we have classified the $124
million of securities that have not been called as long-term investments as of September 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 September 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 September 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, the collection of all
accrued interest to date and continued receipts of principal at par. 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 September 30, 2008. At this time, we do not believe the values of
our long-term securities are impaired.
Pension Plans
Our assets related to our pension plans have been adversely impacted by the performance of the
equity markets in recent months, especially since September 30, 2008. Losses incurred on these
investments will likely cause us to contribute more to our pension plans in 2009 than what would
otherwise have been expected. Such losses will also likely cause an increase in our pension expense
in 2009. However, the amounts of additional contributions and pension expense are not expected to
have a material impact on our liquidity or results of operations.
Critical Accounting Estimates
Full Cost Ceiling Calculations
We follow the full cost method of accounting for our oil and gas properties. As disclosed in
our 2007 Annual Report on Form 10-K/A, the full cost method subjects us to quarterly calculations
of a ceiling, or limitation on the amount of properties that can be capitalized on the balance
sheet. If our net book value of oil and gas properties, less related deferred income taxes,
(recoverable costs) exceeds the calculated ceiling, the excess must be written off as an expense.
The ceiling limitation is imposed separately for each country in which we have oil and gas
properties. As of September 30, 2008, our recoverable costs were less than the calculated ceiling
for all countries.
Subsequent to September 30, 2008, most price indices associated with our oil, natural gas and
NGL reserves declined significantly. These declines have increased the likelihood that our
recoverable costs may exceed the calculated ceiling for
certain countries in future periods, particularly in Brazil where we are in the early stages
of development activities.
45
However, it is not possible at this time to determine what the
calculated ceiling will be as of December 31, 2008. The calculated ceiling at December 31, 2008
will be based on estimates of our proved oil, gas and NGL reserves as of that date and the
associated commodity prices, operating expenses and future development costs on that date.
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.
46
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 |
|
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 September 30, 2008, a 10% increase
in these forward curves would have decreased the net assets recorded for our 2008 and 2009
commodity hedging instruments by approximately $130 million.
Interest Rate Swap Contracts
We have entered into various 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed Rate |
|
|
Variable |
|
|
Notional |
|
|
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 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair values of our interest rate instruments are largely determined by estimates of the
forward curves of the Federal Funds rate and LIBOR. At September 30, 2008, a 10% increase in these
forward curves would have decreased our net assets by approximately $15 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 September 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 third
quarter of 2008 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
47
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 |
|
|
|
|
|
Total Number of |
|
Maximum Number of |
|
|
Number of |
|
Average Price |
|
Shares Purchased as |
|
Shares that May Yet Be |
|
|
Shares |
|
Paid per |
|
Part of Publicly Announced |
|
Purchased Under the |
Period |
|
Purchased |
|
Share |
|
Plans or Programs(1) |
|
Plans or Programs(1) |
July |
|
|
2,828,541 |
|
|
$ |
102.17 |
|
|
|
2,828,541 |
|
|
|
49,126,644 |
|
August |
|
|
810,500 |
|
|
$ |
91.80 |
|
|
|
810,500 |
|
|
|
48,316,144 |
|
September |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
48,316,144 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
3,639,041 |
|
|
$ |
99.86 |
|
|
|
3,639,041 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. As of September 30, 2008, up to 2.8 million shares or $244
million can be repurchased under the ongoing, annual repurchase program and up to 45.5
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
None.
Item 5. Other Information
None.
48
Item 6. Exhibits
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
|
|
|
Exhibit |
|
|
Number |
|
Description |
10.1 |
|
364-Day Credit Agreement dated as of November 5, 2008 among
Registrant as Borrower, Bank of America, N.A. as Administrative
Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The
Other Lenders party thereto, Banc of America Securities LLC and
J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Book
Managers for the $700 Million Short-Term Credit Facility. |
|
|
|
10.2 |
|
Fifth Amendment to Amended and Restated
Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar
Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America,
N.A., individually and as Administrative Agent, and the Lenders party thereto. |
|
|
|
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, Senior 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, Senior 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. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
DEVON ENERGY CORPORATION
|
|
Date: November 6, 2008 |
/s/ Danny J. Heatly
|
|
|
Danny J. Heatly |
|
|
Senior Vice President - Accounting and
Chief Accounting Officer |
|
49
INDEX TO EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Description |
10.1 |
|
364-Day Credit Agreement dated as of November 5, 2008 among
Registrant as Borrower, Bank of America, N.A. as Administrative
Agent, JPMorgan Chase Bank, N.A. as Syndication Agent, and The
Other Lenders party thereto, Banc of America Securities LLC and
J.P. Morgan Securities, Inc. as Joint Lead Arrangers and Book
Managers for the $700 Million Short-Term Credit Facility. |
|
|
|
10.2 |
|
Fifth Amendment to Amended and Restated
Credit Agreement dated as of November 5, 2008, among Registrant as US Borrower, Northstar
Energy Corporation and Devon Canada Corporation as the Canadian Borrowers, Bank of America,
N.A., individually and as Administrative Agent, and the Lenders party thereto. |
|
|
|
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, Senior 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, Senior 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. |
50