e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2009
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State of other jurisdiction of incorporation or organization) |
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73-1567067
(I.R.S. Employer identification No.) |
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20 North Broadway, Oklahoma City, Oklahoma |
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73102-8260 |
(Address of principal executive offices) |
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(Zip code) |
Registrants telephone number, including area code: (405) 235-3611
Former name, former address and former fiscal year, if changed from last report: Not applicable
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ |
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Accelerated filer o |
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Non-accelerated filer o |
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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On April 30, 2009, 443.9 million shares of common stock were outstanding.
[This page intentionally left blank.]
2
DEVON ENERGY CORPORATION
FORM 10-Q
For the Quarterly Period Ended March 31, 2009
INDEX
3
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.
Canada means the division of Devon encompassing oil and gas properties located in Canada.
Domestic means the properties of Devon in the onshore continental United States and the
offshore Gulf of Mexico.
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.
International means the division of Devon encompassing oil and gas properties that lie
outside the United States and Canada.
LIBOR means London Interbank Offered Rate.
Mcf means thousand cubic feet.
MMBbls means million barrels.
MMBoe means million Boe.
MMBtu means million Btu.
NGL or NGLs means natural gas liquids.
NYMEX means New York Mercantile Exchange.
Oil includes crude oil and condensate.
SEC means United States Securities and Exchange Commission.
U.S. Offshore means the properties of Devon in the Gulf of Mexico.
U.S. Onshore means the properties of Devon in the continental United States.
4
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements other than statements of historical facts included or incorporated by
reference in this report, including, without limitation, statements regarding our future financial
position, business strategy, budgets, projected revenues, projected costs and plans and objectives
of management for future operations, are forward-looking statements. Such forward-looking
statements are based on our examination of historical operating trends, the information used to
prepare the December 31, 2008 reserve reports and other data in our possession or available from
third parties. In addition, forward-looking statements generally can be identified by the use of
forward-looking terminology such as may, will, expect, intend, project, estimate,
anticipate, believe, or continue or similar terminology. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can give no assurance
that such expectations will prove to have been correct. Important factors that could cause actual
results to differ materially from our expectations include, but are not limited to, our assumptions
about:
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energy markets, including the supply and demand for oil, gas, NGLs and other products or
services, and the prices of oil, gas, NGLs, including regional pricing differentials, and
other products or services; |
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production levels, including Canadian production subject to government royalties, which
fluctuate with prices and production, and international production governed by payout
agreements, which affect reported production; |
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reserve levels; |
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competitive conditions; |
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technology; |
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the availability of capital resources within the securities or capital markets and
related risks such as general credit, liquidity, market and interest-rate risks; |
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capital expenditure and other contractual obligations; |
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currency exchange rates; |
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the weather; |
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inflation; |
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the availability of goods and services; |
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drilling risks; |
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future processing volumes and pipeline throughput; |
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general economic conditions, whether internationally, nationally or in the jurisdictions
in which we or our subsidiaries conduct business; |
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legislative or regulatory changes, including retroactive royalty or production tax
regimes, changes in environmental regulation, environmental risks and liability under
federal, state and foreign environmental laws and regulations; |
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terrorism; |
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occurrence of property acquisitions or divestitures; and |
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other factors disclosed in Devons 2008 Annual Report on Form 10-K 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.
5
PART I. Financial Information
Item 1. Consolidated Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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March 31, |
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December 31, |
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2009 |
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2008 |
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(Unaudited) |
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(In millions, except |
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share data) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
397 |
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$ |
379 |
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Accounts receivable |
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1,221 |
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1,412 |
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Income taxes receivable |
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106 |
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334 |
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Derivative financial instruments, at fair value |
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327 |
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282 |
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Other current assets |
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325 |
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277 |
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Total current assets |
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2,376 |
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2,684 |
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Property and equipment, at cost, based on the full cost method
of accounting for oil and gas properties ($4,186 and $4,540
excluded from amortization in 2009 and 2008, respectively) |
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56,784 |
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55,657 |
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Less accumulated depreciation, depletion and amortization |
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39,568 |
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32,683 |
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Property and equipment, net |
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17,216 |
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22,974 |
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Goodwill |
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5,509 |
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5,579 |
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Other long-term assets, including $177 million and $199
million at fair value in 2009 and 2008, respectively |
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622 |
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671 |
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Total assets |
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$ |
25,723 |
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$ |
31,908 |
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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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$ |
1,261 |
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$ |
1,819 |
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Revenues and royalties due to others |
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373 |
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496 |
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Short-term debt |
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1,073 |
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180 |
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Current portion of asset retirement obligations, at fair value |
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157 |
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138 |
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Accrued expenses and other current liabilities |
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370 |
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502 |
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Total current liabilities |
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3,234 |
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3,135 |
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Long-term debt |
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5,851 |
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5,661 |
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Asset retirement obligations, at fair value |
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1,340 |
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1,347 |
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Other long-term liabilities |
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992 |
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1,026 |
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Deferred income taxes |
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1,364 |
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3,679 |
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Stockholders equity: |
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Common stock of $0.10 par value. Authorized 1.0 billion
shares; issued 443.9 million and 443.7 million shares in 2009
and 2008, respectively |
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44 |
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44 |
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Additional paid-in capital |
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6,310 |
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6,257 |
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Retained earnings |
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6,347 |
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10,376 |
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Accumulated other comprehensive income |
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241 |
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383 |
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Total stockholders equity |
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12,942 |
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17,060 |
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Commitments and contingencies (Note 8) |
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Total liabilities and stockholders equity |
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$ |
25,723 |
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$ |
31,908 |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months Ended |
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March 31, |
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2009 |
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2008 |
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(Unaudited) |
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(In millions, except |
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per share amounts) |
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Revenues: |
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Oil sales |
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$ |
454 |
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$ |
1,250 |
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Gas sales |
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913 |
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1,630 |
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NGL sales |
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136 |
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328 |
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Net gain (loss) on oil and gas derivative financial instruments |
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154 |
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(788 |
) |
Marketing and midstream revenues |
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371 |
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555 |
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Total revenues |
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2,028 |
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2,975 |
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Expenses and other income, net: |
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Lease operating expenses |
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524 |
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506 |
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Production taxes |
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42 |
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134 |
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Marketing and midstream operating costs and expenses |
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229 |
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382 |
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Depreciation, depletion and amortization of oil and gas properties |
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599 |
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737 |
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Depreciation and amortization of non-oil and gas properties |
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70 |
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57 |
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Accretion of asset retirement obligations |
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24 |
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22 |
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General and administrative expenses |
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166 |
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148 |
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Interest expense |
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83 |
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102 |
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Change in fair value of other financial instruments |
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(5 |
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16 |
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Reduction of carrying value of oil and gas properties |
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6,516 |
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Other expense (income), net |
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7 |
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(21 |
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Total expenses and other income, net |
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8,255 |
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2,083 |
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(Loss) earnings from continuing operations before income taxes |
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(6,227 |
) |
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892 |
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Income tax (benefit) expense: |
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Current |
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2 |
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103 |
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Deferred |
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(2,271 |
) |
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138 |
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Total income tax (benefit) expense |
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(2,269 |
) |
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241 |
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(Loss) earnings from continuing operations |
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(3,958 |
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651 |
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Discontinued operations: |
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(Loss) earnings from discontinued operations before income taxes |
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(1 |
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189 |
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Income tax expense |
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91 |
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(Loss) earnings from discontinued operations |
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(1 |
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98 |
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Net (loss) earnings |
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(3,959 |
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749 |
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Preferred stock dividends |
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2 |
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Net (loss) earnings applicable to common stockholders |
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$ |
(3,959 |
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$ |
747 |
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Basic net (loss) earnings per share: |
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(Loss) earnings from continuing operations |
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$ |
(8.92 |
) |
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$ |
1.46 |
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Earnings from discontinued operations |
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0.22 |
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Net (loss) earnings |
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$ |
(8.92 |
) |
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$ |
1.68 |
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Diluted net (loss) earnings per share: |
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(Loss) earnings from continuing operations |
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$ |
(8.92 |
) |
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$ |
1.44 |
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Earnings from discontinued operations |
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0.22 |
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Net (loss) earnings |
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$ |
(8.92 |
) |
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$ |
1.66 |
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Weighted average common shares outstanding: |
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Basic |
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444 |
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445 |
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Diluted |
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444 |
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449 |
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See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
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Three Months Ended |
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March 31, |
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2009 |
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2008 |
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(Unaudited) |
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(In millions) |
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Net (loss) earnings |
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$ |
(3,959 |
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$ |
749 |
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Foreign currency translation: |
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Change in cumulative translation adjustment |
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(161 |
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(382 |
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Income tax benefit |
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11 |
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17 |
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Total |
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(150 |
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(365 |
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Pension and postretirement benefit plans: |
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Recognition of net actuarial loss and prior service cost
in net (loss) earnings
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12 |
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4 |
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Income tax expense |
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(4 |
) |
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(1 |
) |
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Total |
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8 |
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3 |
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Other comprehensive loss, net of tax |
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(142 |
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(362 |
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Comprehensive (loss) income |
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$ |
(4,101 |
) |
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$ |
387 |
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See accompanying notes to consolidated financial statements.
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
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Accumulated |
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Additional |
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Other |
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Total |
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Preferred |
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Common Stock |
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Paid-In |
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Retained |
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Comprehensive |
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Treasury |
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Stockholders |
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Stock |
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Shares |
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Amount |
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Capital |
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Earnings |
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Income |
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Stock |
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Equity |
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(Unaudited) |
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(In millions) |
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Three Months Ended March 31, 2009: |
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Balance as of December 31, 2008 |
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|
444 |
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$ |
44 |
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$ |
6,257 |
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$ |
10,376 |
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$ |
383 |
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$ |
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$ |
17,060 |
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Net loss |
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(3,959 |
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(3,959 |
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Other comprehensive loss |
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(142 |
) |
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(142 |
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Stock option exercises |
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4 |
|
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4 |
|
Common stock repurchased |
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|
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|
|
(2 |
) |
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|
(2 |
) |
Common stock retired |
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|
|
|
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(2 |
) |
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|
2 |
|
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Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(70 |
) |
|
|
|
|
|
|
|
|
|
|
(70 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49 |
|
Share-based compensation tax
benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2009 |
|
|
|
|
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,310 |
|
|
$ |
6,347 |
|
|
$ |
241 |
|
|
$ |
|
|
|
$ |
12,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007 |
|
$ |
1 |
|
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,743 |
|
|
$ |
12,813 |
|
|
$ |
2,405 |
|
|
$ |
|
|
|
$ |
22,006 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
749 |
|
|
|
|
|
|
|
|
|
|
|
749 |
|
Other comprehensive loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(362 |
) |
|
|
|
|
|
|
(362 |
) |
Stock option exercises |
|
|
|
|
|
|
3 |
|
|
|
1 |
|
|
|
78 |
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
76 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(65 |
) |
|
|
(65 |
) |
Common stock retired |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(68 |
) |
|
|
|
|
|
|
|
|
|
|
68 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
(71 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40 |
|
Share-based compensation tax
benefits |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2008 |
|
$ |
1 |
|
|
|
446 |
|
|
$ |
45 |
|
|
$ |
6,820 |
|
|
$ |
13,489 |
|
|
$ |
2,043 |
|
|
$ |
|
|
|
$ |
22,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net (loss) earnings |
|
$ |
(3,959 |
) |
|
$ |
749 |
|
Loss (earnings) from discontinued operations, net of tax |
|
|
1 |
|
|
|
(98 |
) |
Adjustments to reconcile (loss) earnings from continuing operations
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
669 |
|
|
|
794 |
|
Deferred income tax (benefit) expense |
|
|
(2,271 |
) |
|
|
138 |
|
Reduction of carrying value of oil and gas properties |
|
|
6,516 |
|
|
|
|
|
Net unrealized (gain) loss on oil and gas derivative financial instruments |
|
|
(36 |
) |
|
|
780 |
|
Other noncash charges |
|
|
68 |
|
|
|
74 |
|
Net decrease (increase) in working capital |
|
|
83 |
|
|
|
(377 |
) |
Decrease (increase) in long-term other assets |
|
|
2 |
|
|
|
(11 |
) |
(Decrease) increase in long-term other liabilities |
|
|
(31 |
) |
|
|
21 |
|
|
|
|
|
|
|
|
Cash provided by operating activities continuing operations |
|
|
1,042 |
|
|
|
2,070 |
|
Cash provided by operating activities discontinued operations |
|
|
5 |
|
|
|
185 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
1,047 |
|
|
|
2,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from sales of property and equipment |
|
|
1 |
|
|
|
105 |
|
Capital expenditures |
|
|
(2,019 |
) |
|
|
(1,862 |
) |
Purchases of short-term investments |
|
|
|
|
|
|
(50 |
) |
Sales of long-term and short-term investments |
|
|
2 |
|
|
|
270 |
|
|
|
|
|
|
|
|
Cash used in investing activities continuing operations |
|
|
(2,016 |
) |
|
|
(1,537 |
) |
Cash used in investing activities discontinued operations |
|
|
(14 |
) |
|
|
(24 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(2,030 |
) |
|
|
(1,561 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from borrowings of long-term debt, net of issuance costs |
|
|
1,187 |
|
|
|
|
|
Credit facility repayments |
|
|
|
|
|
|
(1,450 |
) |
Credit facility borrowings |
|
|
|
|
|
|
920 |
|
Net commercial paper (repayments) borrowings |
|
|
(111 |
) |
|
|
442 |
|
Debt repayments |
|
|
(1 |
) |
|
|
(41 |
) |
Proceeds from stock option exercises |
|
|
4 |
|
|
|
74 |
|
Repurchases of common stock |
|
|
|
|
|
|
(64 |
) |
Dividends paid on common and preferred stock |
|
|
(70 |
) |
|
|
(73 |
) |
Excess tax benefits related to share-based compensation |
|
|
2 |
|
|
|
27 |
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities |
|
|
1,011 |
|
|
|
(165 |
) |
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
(11 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
|
17 |
|
|
|
510 |
|
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale) |
|
|
384 |
|
|
|
1,373 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash related
to assets held for sale) |
|
$ |
401 |
|
|
$ |
1,883 |
|
|
|
|
|
|
|
|
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 2008 Annual Report on Form 10-K.
The unaudited interim consolidated financial statements furnished in this report reflect all
adjustments that are, in the opinion of management, necessary to a fair statement of Devons
financial position as of March 31, 2009 and Devons results of operations and cash flows for the
three-month periods ended March 31, 2009 and 2008.
Recently Issued Accounting Standards Not Yet Adopted
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers Disclosures
about Postretirement Benefit Plan Assets. Staff Position 132(R)-1 amends FASB Statement No. 132
(revised 2003), Employers Disclosures about Pensions and Other Postretirement Benefits, to require
additional disclosures about the types of assets and associated risks in an employers defined
benefit pension or other postretirement plan. Staff Position 132(R)-1 is effective for fiscal years
ending after December 15, 2009. Devon is evaluating the impact the adoption of Staff Position
132(R)-1 will have on its financial statement disclosures. However, Devons adoption of Staff
Position 132(R)-1 will not affect its current accounting for its pension and postretirement plans.
Modernization of Oil and Gas Reporting
In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures.
The revisions are intended to provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves. In the three decades that have passed since adoption of
these disclosure items, there have been significant changes in the oil and gas industry. The
amendments are designed to modernize and update the oil and gas disclosure requirements to align
them with current practices and changes in technology. In addition, the amendments concurrently
align the SECs full cost accounting rules with the revised disclosures. The revised disclosure
requirements must be incorporated in registration statements filed on or after January 1, 2010, and
annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may
not apply the new rules to disclosures in quarterly reports prior to the first annual report in
which the revised disclosures are required.
The following amendments have the greatest likelihood of affecting Devons reserve
disclosures, including the comparability of its reserves disclosures with those of its peer
companies:
|
|
|
Pricing mechanism for oil and gas reserves estimation The SECs current rules require
proved reserve estimates to be calculated using prices as of the end of the period and held
constant over the life of the reserves. Price changes can be made only to the extent
provided by contractual arrangements. The revised rules require reserve estimates to be
calculated using a 12-month average price. The 12-month average price will also be used for
purposes of calculating the full cost ceiling limitations. Price changes can still be
incorporated to the extent defined by contractual arrangements. The use of a 12-month
average price rather than a single-day price is expected to reduce the impact on reserve
estimates and the full cost ceiling limitations due to short-term volatility and seasonality
of prices. |
|
|
|
|
Reasonable certainty The SECs current definition of proved oil and gas reserves
incorporate certain specific concepts such as lowest known hydrocarbons, which limits the
ability to claim proved reserves in the absence of information on fluid contacts in a well
penetration, notwithstanding the existence of other engineering and geoscientific evidence.
The revised rules amend the definition to permit the use of new reliable technologies to
establish the reasonable certainty of proved reserves. This revision also includes
provisions for establishing levels of lowest known hydrocarbons and highest known oil
through reliable technology other than well penetrations. |
|
|
|
|
The revised rules also amend the definition of proved oil and gas reserves to include
reserves located beyond development spacing areas that are immediately adjacent to developed
spacing areas if economic producibility can be established with reasonable certainty. These
revisions are designed to permit the use of alternative technologies to
|
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
establish proved
reserves in lieu of requiring companies to use specific tests. In addition, they establish a
uniform standard of reasonable certainty that applies to all proved reserves, regardless of
location or distance from producing wells. |
|
|
|
|
Because the revised rules generally expand the definition of proved reserves, Devon expects
its proved reserve estimates will increase upon adoption of the revised rules. However, Devon
is not able to estimate the magnitude of the potential increase at this time. |
|
|
|
|
Unproved reserves The SECs current rules prohibit disclosure of reserve estimates
other than proved in documents filed with the SEC. The revised rules permit disclosure of
probable and possible reserves and provide definitions of probable reserves and possible
reserves. Disclosure of probable and possible reserves is optional. However, such
disclosures must meet specific requirements. Disclosures of probable or possible reserves
must provide the same level of geographic detail as proved reserves and must state whether
the reserves are developed or undeveloped. Probable and possible reserve disclosures must
also provide the relative uncertainty associated with these classifications of reserves
estimations. Devon has not yet determined whether it will disclose its probable and possible
reserves in documents filed with the SEC. |
2. Derivative Financial Instruments
Devon periodically enters into commodity and interest rate derivative financial instruments.
These instruments are used to manage the inherent uncertainty of future revenues due to oil and gas
price volatility and to manage Devons exposure to interest rate volatility. Also, during the first
eight months of 2008, Devon was subject to an embedded option derivative related to the fair value
of its debentures exchangeable into shares of Chevron common stock.
The following table presents the fair values of derivative assets and liabilities included in
the accompanying balance sheets. None of Devons derivative instruments included in the table have
been designated as hedging instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Caption |
|
Asset |
|
|
Liability |
|
|
|
|
|
(In millions) |
|
March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
Gas price collars |
|
Derivative financial instruments, current |
|
$ |
291 |
|
|
$ |
|
|
Interest rate swaps |
|
Derivative financial instruments, current |
|
|
36 |
|
|
|
|
|
Interest rate swaps |
|
Long-term other assets |
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
|
|
$ |
384 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008: |
|
|
|
|
|
|
|
|
|
|
Gas price collars |
|
Derivative financial instruments, current |
|
$ |
255 |
|
|
$ |
|
|
Interest rate swaps |
|
Derivative financial instruments, current |
|
|
27 |
|
|
|
|
|
Interest rate swaps |
|
Long-term other assets |
|
|
77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivatives |
|
|
|
$ |
359 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The following table presents the cash settlements and unrealized gains and losses on fair
value changes included in the accompanying statements of operations associated with these
derivative financial instruments. None of Devons derivative instruments included in the table have
been designated as hedging instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Statement of Operations Caption |
|
Ended March 31, |
|
|
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
(In millions) |
|
Cash settlement receipts
(payments): |
|
|
|
|
|
|
|
|
|
|
Gas price collars |
|
Net gain (loss) on oil and gas derivative financial instruments |
|
$ |
118 |
|
|
$ |
|
|
Gas price swaps |
|
Net gain (loss) on oil and gas derivative financial instruments |
|
|
|
|
|
|
(8 |
) |
Interest rate swaps |
|
Change in fair value of other financial instruments |
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
|
|
134 |
|
|
|
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized gains (losses): |
|
|
|
|
|
|
|
|
|
|
Oil price collars |
|
Net gain (loss) on oil and gas derivative financial instruments |
|
|
|
|
|
|
(1 |
) |
Gas price collars |
|
Net gain (loss) on oil and gas derivative financial instruments |
|
|
36 |
|
|
|
(408 |
) |
Gas price swaps |
|
Net gain (loss) on oil and gas derivative financial instruments |
|
|
|
|
|
|
(371 |
) |
Interest rate swaps |
|
Change in fair value of other financial instruments |
|
|
(11 |
) |
|
|
|
|
Embedded option |
|
Change in fair value of other financial instruments |
|
|
|
|
|
|
97 |
|
|
|
|
|
|
|
|
|
|
Total unrealized gains (losses) |
|
|
|
|
25 |
|
|
|
(683 |
) |
|
|
|
|
|
|
|
|
|
Net gain (loss) recognized on statement of operations |
|
$ |
159 |
|
|
$ |
(691 |
) |
|
|
|
|
|
|
|
|
|
3. Other Current Assets
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
|
December 31, 2008 |
|
|
|
(In millions) |
|
Inventories |
|
$ |
244 |
|
|
$ |
195 |
|
Prepaid assets |
|
|
52 |
|
|
|
49 |
|
Other |
|
|
29 |
|
|
|
33 |
|
|
|
|
|
|
|
|
Other current assets |
|
$ |
325 |
|
|
$ |
277 |
|
|
|
|
|
|
|
|
4. Property and Equipment and Asset Retirement Obligations
In the first quarter of 2009, Devon reduced the carrying values of certain of its oil and gas
properties due to full cost ceiling limitations. These reductions are discussed in Note 10.
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The following is a summary of the changes in Devons asset retirement obligation (ARO) for
the first three months of 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
ARO as of beginning of period |
|
$ |
1,485 |
|
|
$ |
1,318 |
|
Liabilities incurred |
|
|
8 |
|
|
|
16 |
|
Liabilities settled |
|
|
(26 |
) |
|
|
(25 |
) |
Revision of estimated obligation |
|
|
23 |
|
|
|
140 |
|
Accretion expense on discounted obligation |
|
|
24 |
|
|
|
22 |
|
Foreign currency translation adjustment |
|
|
(17 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
|
ARO as of end of period |
|
|
1,497 |
|
|
|
1,445 |
|
Less current portion |
|
|
157 |
|
|
|
68 |
|
|
|
|
|
|
|
|
ARO, long-term |
|
$ |
1,340 |
|
|
$ |
1,377 |
|
|
|
|
|
|
|
|
5. Debt
5.625% Senior Notes Due January 15, 2014 and 6.30% Senior Notes Due January 15, 2019
In January 2009, Devon issued $500 million of 5.625% senior unsecured notes due January 15,
2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds
received of $1.187 billion, after discounts and issuance costs, were used primarily to repay
Devons $1.0 billion of outstanding commercial paper as of December 31, 2008.
Credit Lines
Devon has two revolving lines of credit that can be accessed to provide liquidity as needed.
The following schedule summarizes the capacity of Devons credit facilities by maturity date, as
well as its available capacity as of March 31, 2009.
|
|
|
|
|
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 November 3, 2009 maturity |
|
|
700 |
|
|
|
|
|
Total credit facility capacity |
|
|
3,350 |
|
Less: |
|
|
|
|
Outstanding credit facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
894 |
|
Outstanding letters of credit |
|
|
112 |
|
|
|
|
|
Total available capacity |
|
$ |
2,344 |
|
|
|
|
|
The credit facilities contain only one material financial covenant. This covenant requires
Devons ratio of total funded debt to total capitalization to be less than 65%. The credit
agreement contains definitions of total funded debt and total capitalization that include
adjustments to the respective amounts reported in the consolidated financial statements. Also,
total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling
impairments or goodwill impairments. As of March 31, 2009, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at March 31, 2009, as calculated pursuant to the
terms of the agreement, was 21.3%.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Commercial Paper
Subsequent to the $1.0 billion commercial paper repayment in January 2009, Devon utilized
additional commercial paper borrowings of $894 million to fund capital expenditure payments in
excess of first quarter cash generated by operating activities. As of March 31, 2009, Devons
average borrowing rate on its $894 million of commercial paper debt was 0.70%.
6. Retirement Plans
Net Periodic Benefit Cost and Other Comprehensive Income
The following table presents the components of net periodic benefit cost and other
comprehensive income for Devons pension and other post retirement benefit plans for the
three-month periods ended March 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
11 |
|
|
$ |
10 |
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
14 |
|
|
|
14 |
|
|
|
1 |
|
|
|
2 |
|
Expected return on plan assets |
|
|
(9 |
) |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net actuarial loss |
|
|
11 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
|
28 |
|
|
|
15 |
|
|
|
1 |
|
|
|
2 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of prior service cost in net
periodic benefit cost |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial loss in net
periodic benefit cost |
|
|
(11 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized |
|
$ |
16 |
|
|
$ |
11 |
|
|
$ |
1 |
|
|
$ |
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon previously disclosed in its 2008 Annual Report on Form 10-K that it expected to
contribute up to approximately $183 million to its defined benefit pension plans in 2009 and $5
million to its defined benefit postretirement plans in 2009. Devon has revised its estimate of 2009
defined benefit pension plan contributions to $55 million. As of March 31, 2009, Devon has
contributed $14 million to its defined benefit pension plans and $1 million to its defined benefit
postretirement plans.
7. Stockholders Equity
Stock Repurchases
During the first quarter of 2008, Devon repurchased 0.8 million shares for $64 million, or
$79.37 per share. These repurchases were made under Devons ongoing, annual stock repurchase
program approved by its Board of Directors. No such repurchases were made during the first quarter
of 2009.
Dividends
Devon paid common stock dividends of $70 million and $71 million (quarterly rates of $0.16 per
share) in the first quarter of 2009 and 2008, respectively. Devon paid preferred stock dividends of
$2 million in the first quarter of 2008. Devon redeemed all 1.5 million outstanding shares of its
preferred stock on June 20, 2008.
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
8. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that
are probable of unfavorable outcome to Devon and that can be reasonably estimated are accrued. Such
accruals are based on information known about the matters, Devons estimates of the outcomes of
such matters and its experience in contesting, litigating and settling similar matters. None of the
actions are believed by management to involve future amounts that would be material to Devons
financial position or results of operations after consideration of recorded accruals. However,
actual amounts could differ materially from managements estimate.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation
activities associated with past operations, such as the Comprehensive Environmental Response,
Compensation, and Liability Act (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 March 31,
2009, 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.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in
various lawsuits alleging violation of the federal False Claims Act. The suits allege that the
producers and related parties used below-market prices, improper deductions, improper measurement
techniques and transactions with affiliates, which resulted in underpayment of royalties in
connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled
lands. 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 was scheduled to begin in February 2009, but the defendants settled prior to
trial. Devon was 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 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.
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The U.S. House of Representatives in January 2007 passed legislation that would have required
companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases.
This legislation was not passed by the U.S. Senate. However, Congress may consider similar
legislation in the future. In October 2007 a federal district court ruled in favor of a plaintiff
who had challenged the legality of including price thresholds in deep water leases. Additionally,
in January 2009 a federal appellate court upheld this district court ruling. This judgment is
subject to further appeals.
As of March 31, 2009, Devon had $82 million accrued for potential royalties on various deep
water leases. Due to the uncertainty of this issue caused by the favorable federal court decisions
and potential Congressional actions, Devon has ceased accruing additional royalties on its affected
leases. Devon will continue to monitor developments and adjust its accruals as necessary.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business.
However, to Devons knowledge as of the date of this report, neither Devon nor its property is
subject to any material pending legal proceedings.
9. 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 carrying value and fair value measurement information for
such assets and liabilities as of March 31, 2009 and December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 31, 2009 |
|
|
|
|
|
|
|
|
|
|
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): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term investments |
|
$ |
120 |
|
|
$ |
120 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
120 |
|
Gas price collars |
|
$ |
291 |
|
|
$ |
291 |
|
|
$ |
|
|
|
$ |
291 |
|
|
$ |
|
|
Interest rate swaps |
|
$ |
93 |
|
|
$ |
93 |
|
|
$ |
|
|
|
$ |
93 |
|
|
$ |
|
|
Debt |
|
$ |
(6,924 |
) |
|
$ |
(7,079 |
) |
|
$ |
(894 |
) |
|
$ |
(6,185 |
) |
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,497 |
) |
|
$ |
(1,497 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,497 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 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): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term investments |
|
$ |
122 |
|
|
$ |
122 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
122 |
|
Gas price collars |
|
$ |
255 |
|
|
$ |
255 |
|
|
$ |
|
|
|
$ |
255 |
|
|
$ |
|
|
Interest rate swaps |
|
$ |
104 |
|
|
$ |
104 |
|
|
$ |
|
|
|
$ |
104 |
|
|
$ |
|
|
Debt |
|
$ |
(5,841 |
) |
|
$ |
(6,106 |
) |
|
$ |
(1,005 |
) |
|
$ |
(5,101 |
) |
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,485 |
) |
|
$ |
(1,485 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,485 |
) |
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Included below is a summary of the changes in Devons Level 3 fair value measurements during
the first quarter of 2009 (in millions).
|
|
|
|
|
Beginning balance |
|
$ |
122 |
|
Redemptions of principal |
|
|
(2 |
) |
|
|
|
|
Ending balance |
|
$ |
120 |
|
|
|
|
|
10. Reduction of Carrying Value of Oil and Gas Properties
In the first quarter of 2009, Devon reduced the carrying values of certain of its oil and gas
properties due to full cost ceiling limitations. A summary of these reductions and additional
discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
|
|
|
|
|
|
Net of |
|
|
|
Gross |
|
|
Taxes |
|
|
|
(In millions) |
|
United States |
|
$ |
6,408 |
|
|
$ |
4,085 |
|
Brazil |
|
|
103 |
|
|
|
103 |
|
Russia |
|
|
5 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Total |
|
$ |
6,516 |
|
|
$ |
4,190 |
|
|
|
|
|
|
|
|
The United States reduction resulted primarily from a significant decrease in the full cost
ceiling during the first three months of 2009. The lower ceiling value in the United States largely
resulted from the continued effects of declining natural gas prices subsequent to December 31,
2008.
Although oil prices improved subsequent to December 31, 2008, Brazils reduction resulted
largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin.
After drilling this well in the first quarter of 2009, Devon concluded that the well did not have
adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs
associated with this well contributed to the reduction recognized in the first quarter of 2009.
To demonstrate the changes in the full-cost ceiling for the United States and Brazil, the
March 31, 2009 and December 31, 2008 weighted average wellhead prices are presented in the
following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
December 31, 2008 |
|
|
Oil |
|
Gas |
|
NGLs |
|
Oil |
|
Gas |
|
NGLs |
Country |
|
(Per Bbl) |
|
(Per Mcf) |
|
(Per Bbl) |
|
(Per Bbl) |
|
(Per Mcf) |
|
(Per Bbl) |
United States |
|
$ |
47.30 |
|
|
$ |
2.67 |
|
|
$ |
17.04 |
|
|
$ |
42.21 |
|
|
$ |
4.68 |
|
|
$ |
16.16 |
|
Brazil |
|
$ |
36.71 |
|
|
|
N/A |
|
|
|
N/A |
|
|
$ |
26.61 |
|
|
|
N/A |
|
|
|
N/A |
|
The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash
price of $49.66 per Bbl for crude oil and the Henry hub spot price of $3.63 per MMBtu for gas. The
December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of
$44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas.
11. Discontinued Operations
Operating revenues related to Devons discontinued operations totaled $205 million in the
three months ended March 31, 2008.
18
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 March 31, 2009 and December 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
Devons Consolidated |
|
March 31, |
|
|
December 31, |
|
|
|
Balance Sheet Caption |
|
2009 |
|
|
2008 |
|
|
|
|
|
(In millions) |
|
Assets: |
|
|
|
|
|
|
|
|
|
|
Cash |
|
Other current assets |
|
$ |
4 |
|
|
$ |
5 |
|
Other current assets |
|
Other current assets |
|
|
20 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
Other current assets |
|
$ |
24 |
|
|
$ |
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term assets property and equipment, net of
accumulated depreciation, depletion and amortization |
|
Other long-term assets |
|
$ |
36 |
|
|
$ |
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
Accounts payable trade |
|
Other current liabilities |
|
$ |
15 |
|
|
$ |
7 |
|
Accrued expenses and other current liabilities |
|
Other current liabilities |
|
|
5 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
Other current liabilities |
|
$ |
20 |
|
|
$ |
13 |
|
|
|
|
|
|
|
|
|
|
12. (Loss) Earnings Per Share
The following table reconciles (loss) earnings from continuing operations and common shares
outstanding used in the calculations of basic and diluted (loss) earnings per share for the
three-month periods ended March 31, 2009 and 2008. Because a net loss from continuing operations
was generated during the three-month period ended March 31, 2009, the dilutive shares produce an
antidilutive net loss per share result. Therefore, the diluted loss per share from continuing
operations reported in the accompanying 2009 statement of operations is the same as the basic loss
per share amount.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (Loss) |
|
|
Weighted |
|
|
|
|
|
|
Earnings |
|
|
Average |
|
|
|
|
|
|
Applicable to |
|
|
Common |
|
|
Net (Loss) |
|
|
|
Common |
|
|
Shares |
|
|
Earnings |
|
|
|
Stockholders |
|
|
Outstanding |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted loss per share |
|
$ |
(3,958 |
) |
|
|
444 |
|
|
$ |
(8.92 |
) |
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
651 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
649 |
|
|
|
445 |
|
|
$ |
1.46 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
649 |
|
|
|
449 |
|
|
$ |
1.44 |
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. These excluded options totaled 8.9 million and
1.8 million during the three-month periods ended March 31, 2009 and 2008.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
13. 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 March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
1,557 |
|
|
$ |
464 |
|
|
$ |
355 |
|
|
$ |
2,376 |
|
Property and equipment, net |
|
|
11,954 |
|
|
|
4,390 |
|
|
|
872 |
|
|
|
17,216 |
|
Goodwill |
|
|
3,046 |
|
|
|
2,395 |
|
|
|
68 |
|
|
|
5,509 |
|
Other long-term assets |
|
|
310 |
|
|
|
61 |
|
|
|
251 |
|
|
|
622 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
16,867 |
|
|
$ |
7,310 |
|
|
$ |
1,546 |
|
|
$ |
25,723 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
2,522 |
|
|
$ |
403 |
|
|
$ |
309 |
|
|
$ |
3,234 |
|
Long-term debt |
|
|
2,872 |
|
|
|
2,979 |
|
|
|
|
|
|
|
5,851 |
|
Asset retirement obligation, long-term |
|
|
708 |
|
|
|
532 |
|
|
|
100 |
|
|
|
1,340 |
|
Other long-term liabilities |
|
|
951 |
|
|
|
38 |
|
|
|
3 |
|
|
|
992 |
|
Deferred income taxes |
|
|
448 |
|
|
|
851 |
|
|
|
65 |
|
|
|
1,364 |
|
Stockholders equity |
|
|
9,366 |
|
|
|
2,507 |
|
|
|
1,069 |
|
|
|
12,942 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
16,867 |
|
|
$ |
7,310 |
|
|
$ |
1,546 |
|
|
$ |
25,723 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended March 31, 2009: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
150 |
|
|
$ |
177 |
|
|
$ |
127 |
|
|
$ |
454 |
|
Gas sales |
|
|
676 |
|
|
|
236 |
|
|
|
1 |
|
|
|
913 |
|
NGL sales |
|
|
112 |
|
|
|
24 |
|
|
|
|
|
|
|
136 |
|
Net gain on oil and gas derivative financial instruments |
|
|
154 |
|
|
|
|
|
|
|
|
|
|
|
154 |
|
Marketing and midstream revenues |
|
|
364 |
|
|
|
7 |
|
|
|
|
|
|
|
371 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,456 |
|
|
|
444 |
|
|
|
128 |
|
|
|
2,028 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
313 |
|
|
|
177 |
|
|
|
34 |
|
|
|
524 |
|
Production taxes |
|
|
32 |
|
|
|
|
|
|
|
10 |
|
|
|
42 |
|
Marketing and midstream operating costs and expenses |
|
|
224 |
|
|
|
4 |
|
|
|
1 |
|
|
|
229 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
440 |
|
|
|
120 |
|
|
|
39 |
|
|
|
599 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
64 |
|
|
|
6 |
|
|
|
|
|
|
|
70 |
|
Accretion of asset retirement obligation |
|
|
14 |
|
|
|
9 |
|
|
|
1 |
|
|
|
24 |
|
General and administrative expenses |
|
|
137 |
|
|
|
29 |
|
|
|
|
|
|
|
166 |
|
Interest expense |
|
|
27 |
|
|
|
56 |
|
|
|
|
|
|
|
83 |
|
Change in fair value of other financial instruments |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
Reduction of carrying value of oil and gas properties |
|
|
6,408 |
|
|
|
|
|
|
|
108 |
|
|
|
6,516 |
|
Other expense (income), net |
|
|
(3 |
) |
|
|
10 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
7,651 |
|
|
|
411 |
|
|
|
193 |
|
|
|
8,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations before income
taxes |
|
|
(6,195 |
) |
|
|
33 |
|
|
|
(65 |
) |
|
|
(6,227 |
) |
Income tax (benefit) expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(10 |
) |
|
|
2 |
|
|
|
10 |
|
|
|
2 |
|
Deferred |
|
|
(2,279 |
) |
|
|
7 |
|
|
|
1 |
|
|
|
(2,271 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax (benefit) expense |
|
|
(2,289 |
) |
|
|
9 |
|
|
|
11 |
|
|
|
(2,269 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) earnings from continuing operations |
|
|
(3,906 |
) |
|
|
24 |
|
|
|
(76 |
) |
|
|
(3,958 |
) |
Loss from discontinued operations |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) earnings applicable to common stockholders |
|
$ |
(3,906 |
) |
|
$ |
24 |
|
|
$ |
(77 |
) |
|
$ |
(3,959 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
1,148 |
|
|
$ |
301 |
|
|
$ |
73 |
|
|
$ |
1,522 |
|
Revision of future ARO |
|
|
37 |
|
|
|
(15 |
) |
|
|
1 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,185 |
|
|
$ |
286 |
|
|
$ |
74 |
|
|
$ |
1,545 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
(In millions) |
|
Three Months Ended March 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
443 |
|
|
$ |
340 |
|
|
$ |
467 |
|
|
$ |
1,250 |
|
Gas sales |
|
|
1,263 |
|
|
|
389 |
|
|
|
5 |
|
|
|
1,630 |
|
NGL sales |
|
|
266 |
|
|
|
62 |
|
|
|
|
|
|
|
328 |
|
Net loss on oil and gas derivative financial instruments |
|
|
(788 |
) |
|
|
|
|
|
|
|
|
|
|
(788 |
) |
Marketing and midstream revenues |
|
|
542 |
|
|
|
13 |
|
|
|
|
|
|
|
555 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,699 |
|
|
|
804 |
|
|
|
472 |
|
|
|
2,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
266 |
|
|
|
194 |
|
|
|
46 |
|
|
|
506 |
|
Production taxes |
|
|
79 |
|
|
|
1 |
|
|
|
54 |
|
|
|
134 |
|
Marketing and midstream operating costs and expenses |
|
|
377 |
|
|
|
5 |
|
|
|
|
|
|
|
382 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
460 |
|
|
|
211 |
|
|
|
66 |
|
|
|
737 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
51 |
|
|
|
6 |
|
|
|
|
|
|
|
57 |
|
Accretion of asset retirement obligation |
|
|
11 |
|
|
|
10 |
|
|
|
1 |
|
|
|
22 |
|
General and administrative expenses |
|
|
114 |
|
|
|
34 |
|
|
|
|
|
|
|
148 |
|
Interest expense |
|
|
52 |
|
|
|
50 |
|
|
|
|
|
|
|
102 |
|
Change in fair value of other financial instruments |
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
Other income, net |
|
|
(6 |
) |
|
|
(5 |
) |
|
|
(10 |
) |
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,420 |
|
|
|
506 |
|
|
|
157 |
|
|
|
2,083 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
279 |
|
|
|
298 |
|
|
|
315 |
|
|
|
892 |
|
Income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
46 |
|
|
|
18 |
|
|
|
39 |
|
|
|
103 |
|
Deferred |
|
|
50 |
|
|
|
48 |
|
|
|
40 |
|
|
|
138 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
96 |
|
|
|
66 |
|
|
|
79 |
|
|
|
241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
183 |
|
|
|
232 |
|
|
|
236 |
|
|
|
651 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income taxes |
|
|
|
|
|
|
|
|
|
|
189 |
|
|
|
189 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
91 |
|
|
|
91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
98 |
|
|
|
98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
183 |
|
|
|
232 |
|
|
|
334 |
|
|
|
749 |
|
Preferred stock dividends |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
181 |
|
|
$ |
232 |
|
|
$ |
334 |
|
|
$ |
747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,311 |
|
|
$ |
516 |
|
|
$ |
151 |
|
|
$ |
1,978 |
|
Revision of future ARO |
|
|
70 |
|
|
|
73 |
|
|
|
(3 |
) |
|
|
140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,381 |
|
|
$ |
589 |
|
|
$ |
148 |
|
|
$ |
2,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
14. Supplemental Information to Statements of Cash Flows
Additional information related to Devons cash flows for the three-month periods ended March
31, 2009 and 2008 are presented below:
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Net decrease (increase) in working capital: |
|
|
|
|
|
|
|
|
Decrease (increase) in accounts receivable |
|
$ |
206 |
|
|
$ |
(328 |
) |
Decrease (increase) in other current assets |
|
|
185 |
|
|
|
(39 |
) |
(Decrease) increase in accounts payable |
|
|
(25 |
) |
|
|
38 |
|
(Decrease) increase in revenues and royalties due to others |
|
|
(117 |
) |
|
|
119 |
|
Decrease in other current liabilities |
|
|
(166 |
) |
|
|
(167 |
) |
|
|
|
|
|
|
|
Net decrease (increase) in working capital |
|
$ |
83 |
|
|
$ |
(377 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data continuing and discontinued operations: |
|
|
|
|
|
|
|
|
Interest paid net of capitalized interest |
|
$ |
98 |
|
|
$ |
136 |
|
Income taxes (received) paid |
|
$ |
(177 |
) |
|
$ |
83 |
|
23
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion addresses material changes in our results of operations and capital
resources and uses for the three-month period ended March 31, 2009, compared to the three-month
period ended March 31, 2008, and in our financial condition and liquidity since December 31, 2008.
For information regarding our critical accounting policies and estimates, see our 2008 Annual
Report on Form 10-K under Item 7. Managements Discussion and Analysis of Financial Condition and
Results of Operations. Unless otherwise stated, all dollar amounts are expressed in U.S. dollars.
Business Overview
The downward pressure in natural gas prices that began in the last half of 2008 has continued
into the first quarter of 2009. The Henry Hub natural gas index decreased 29% from the fourth
quarter of 2008 to the first quarter of 2009, and 39% from the first quarter of 2008. Additionally,
although oil index prices have improved slightly since the end of 2008, the West Texas Intermediate
oil index dropped 56% from the first quarter of 2008 to the first quarter of 2009.
As a result, our earnings for the first three months ended March 31, 2009 were negatively
impacted. During the first quarter of 2009, we generated a net loss of $4.0 billion, or $8.92 per
diluted share, representing a significant change compared to the same period of 2008. The loss in
the 2009 quarter was the result of noncash impairments of our oil and gas properties that totaled
$4.2 billion, net of income taxes. Substantially all of this noncash charge was the result of the
continuing drop in natural gas prices in the first quarter.
Key measures of our performance for the first quarter of 2009 compared to the first quarter of
2008 are summarized below:
|
|
|
Production increased 6% to 62 million Boe. |
|
|
|
|
The combined realized price without hedges for oil, gas and NGLs decreased 56% to $24.39
per Boe. |
|
|
|
|
Marketing and midstream operating profit decreased 18% to $142 million. |
|
|
|
|
Per unit operating costs decreased 16% to $9.19 per Boe. |
|
|
|
|
Oil and gas hedges generated a net gain of $154 million in the first quarter of 2009 and
a net loss of $788 million in the first quarter of 2008. Included in these amounts were cash
receipts of $118 million and payments of $8 million, respectively. |
|
|
|
|
General and administrative expenses increased 12% to $166 million. |
|
|
|
|
Operating cash flow decreased 54% to $1.0 billion in the first quarter of 2009. |
|
|
|
|
Cash spent on capital expenditures was approximately $2.0 billion in the first quarter of
2009. Approximately half this amount was funded with operating cash flow and the remainder
was funded with commercial paper borrowings. |
Additionally, in January 2009, we issued $500 million of 5.625% senior unsecured notes due
January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net
proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to
repay our $1.0 billion of outstanding commercial paper as of December 31, 2008.
Although oil and gas prices remain depressed compared to recent highs achieved in 2008, and
our operating cash flow has been negatively impacted, we expect to have adequate liquidity to
execute our near-term operating strategy and maintain momentum on our longer-term projects. As of
April 30, 2009, we had unused lines of credit totaling $2.2 billion and continue to have access to
the commercial paper market. We anticipate these capital sources combined with our operating cash
flow will be sufficient to fund our planned capital expenditures and other capital uses over the
near-term.
24
Results of Operations
Revenues
The three-month comparison of our oil, gas and NGL production, prices and revenues for the
first quarters of 2009 and 2008 are shown in the following tables. The amounts for all periods
presented exclude our West African operations that were sold in the second and third quarters of
2008 and are classified as discontinued operations in our financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
13 |
|
|
|
14 |
|
|
|
-5 |
% |
Gas (Bcf) |
|
|
245 |
|
|
|
223 |
|
|
|
+10 |
% |
NGLs (MMBbls) |
|
|
7 |
|
|
|
7 |
|
|
|
+6 |
% |
Total (MMBoe)(1) |
|
|
62 |
|
|
|
58 |
|
|
|
+6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
33.61 |
|
|
$ |
88.23 |
|
|
|
-62 |
% |
Gas (per Mcf) |
|
$ |
3.73 |
|
|
$ |
7.31 |
|
|
|
-49 |
% |
NGLs (per Bbl) |
|
$ |
18.60 |
|
|
$ |
47.40 |
|
|
|
-61 |
% |
Combined (per Boe)(1) |
|
$ |
24.39 |
|
|
$ |
55.07 |
|
|
|
-56 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
454 |
|
|
$ |
1,250 |
|
|
|
-64 |
% |
Gas sales |
|
|
913 |
|
|
|
1,630 |
|
|
|
-44 |
% |
NGL sales |
|
|
136 |
|
|
|
328 |
|
|
|
-58 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,503 |
|
|
$ |
3,208 |
|
|
|
-53 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic |
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
4 |
|
|
|
4 |
|
|
|
-12 |
% |
Gas (Bcf) |
|
|
192 |
|
|
|
171 |
|
|
|
+12 |
% |
NGLs (MMBbls) |
|
|
6 |
|
|
|
6 |
|
|
|
+8 |
% |
Total (MMBoe)(1) |
|
|
43 |
|
|
|
39 |
|
|
|
+9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
36.89 |
|
|
$ |
95.70 |
|
|
|
-61 |
% |
Gas (per Mcf) |
|
$ |
3.53 |
|
|
$ |
7.24 |
|
|
|
-51 |
% |
NGLs (per Bbl) |
|
$ |
17.53 |
|
|
$ |
44.86 |
|
|
|
-61 |
% |
Combined (per Boe)(1) |
|
$ |
22.11 |
|
|
$ |
49.84 |
|
|
|
-56 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
150 |
|
|
$ |
443 |
|
|
|
-66 |
% |
Gas sales |
|
|
676 |
|
|
|
1,236 |
|
|
|
-45 |
% |
NGL sales |
|
|
112 |
|
|
|
266 |
|
|
|
-58 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
938 |
|
|
$ |
1,945 |
|
|
|
-52 |
% |
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
6 |
|
|
|
5 |
|
|
|
+35 |
% |
Gas (Bcf) |
|
|
53 |
|
|
|
52 |
|
|
|
+2 |
% |
NGLs (MMBbls) |
|
|
1 |
|
|
|
1 |
|
|
|
-5 |
% |
Total (MMBoe)(1) |
|
|
16 |
|
|
|
14 |
|
|
|
+13 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
27.89 |
|
|
$ |
72.68 |
|
|
|
-62 |
% |
Gas (per Mcf) |
|
$ |
4.48 |
|
|
$ |
7.53 |
|
|
|
-41 |
% |
NGLs (per Bbl) |
|
$ |
25.85 |
|
|
$ |
62.67 |
|
|
|
-59 |
% |
Combined (per Boe)(1) |
|
$ |
27.21 |
|
|
$ |
55.42 |
|
|
|
-51 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
177 |
|
|
$ |
340 |
|
|
|
-48 |
% |
Gas sales |
|
|
236 |
|
|
|
389 |
|
|
|
-39 |
% |
NGL sales |
|
|
24 |
|
|
|
62 |
|
|
|
-61 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
437 |
|
|
$ |
791 |
|
|
|
-45 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
3 |
|
|
|
5 |
|
|
|
-36 |
% |
Gas (Bcf) |
|
|
|
|
|
|
|
|
|
|
-45 |
% |
NGLs (MMBbls) |
|
|
|
|
|
|
|
|
|
|
N/M |
|
Total (MMBoe)(1) |
|
|
3 |
|
|
|
5 |
|
|
|
-36 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl) |
|
$ |
41.00 |
|
|
$ |
96.08 |
|
|
|
-57 |
% |
Gas (per Mcf) |
|
$ |
3.47 |
|
|
$ |
8.41 |
|
|
|
-59 |
% |
NGLs (per Bbl) |
|
$ |
|
|
|
$ |
|
|
|
|
N/M |
|
Combined (per Boe)(1) |
|
$ |
40.68 |
|
|
$ |
95.24 |
|
|
|
-57 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
127 |
|
|
$ |
467 |
|
|
|
-73 |
% |
Gas sales |
|
|
1 |
|
|
|
5 |
|
|
|
-77 |
% |
NGL sales |
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
128 |
|
|
$ |
472 |
|
|
|
-73 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 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 March 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2008 sales |
|
$ |
1,250 |
|
|
$ |
1,630 |
|
|
$ |
328 |
|
|
$ |
3,208 |
|
Changes due to volumes |
|
|
(59 |
) |
|
|
159 |
|
|
|
19 |
|
|
|
119 |
|
Changes due to prices |
|
|
(737 |
) |
|
|
(876 |
) |
|
|
(211 |
) |
|
|
(1,824 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 sales |
|
$ |
454 |
|
|
$ |
913 |
|
|
$ |
136 |
|
|
$ |
1,503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
Oil Sales
Oil sales decreased $737 million in the first quarter of 2009 as a result of a 62% decrease in
our realized price without hedges. The average NYMEX West Texas Intermediate index price decreased
56% during the same time period, accounting for the majority of the decrease.
Oil sales decreased $59 million in the first quarter of 2009 due to a one million barrel
decrease in production. Our International production decreased approximately two million barrels
due to reaching certain cost recovery thresholds of our carried interest in Azerbaijan. Also, we
deferred approximately 0.3 million barrels of Gulf of Mexico oil production due to hurricanes.
These decreases were partially offset by additional production of almost two million barrels from
our Jackfish operation in Canada.
Gas Sales
Gas sales decreased $876 million during the first quarter of 2009 as a result of a 49%
decrease in our realized price without hedges. This decrease was largely due to decreases in the
North American regional index prices upon which our gas sales are based.
A 22 Bcf increase in production during the first quarter of 2009 caused gas sales to increase
by $159 million. Our drilling and development program in the Barnett Shale field in north Texas
contributed 15 Bcf to the gas production increase. This increase and the effect of new drilling and
development in our other North American properties were partially offset by natural production
declines, mainly in the Gulf of Mexico, and the deferral of two Bcf of production due to hurricane
damage suffered in the third quarter of 2008.
NGL Sales
NGL sales decreased $211 million during the first quarter of 2009 as a result of a 61%
decrease in our realized price without hedges. This decrease was largely due to decreases in the
regional index prices upon which our NGL 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 first quarters of 2009 and 2008. 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 first quarters of
2009 and 2008. The prices do not include the effects of unrealized gains and losses.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
|
|
|
$ |
(8 |
) |
Gas price collars |
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements received (paid) |
|
|
118 |
|
|
|
(8 |
) |
|
|
|
|
|
|
|
Unrealized gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
|
|
|
|
(371 |
) |
Gas price collars |
|
|
36 |
|
|
|
(408 |
) |
Oil price collars |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
Total unrealized gains (losses) on fair value changes |
|
|
36 |
|
|
|
(780 |
) |
|
|
|
|
|
|
|
Net gain (loss) on oil and gas derivative financial instruments |
|
$ |
154 |
|
|
$ |
(788 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2009 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
33.61 |
|
|
$ |
3.73 |
|
|
$ |
18.60 |
|
|
$ |
24.39 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.48 |
|
|
|
|
|
|
|
1.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
33.61 |
|
|
$ |
4.21 |
|
|
$ |
18.60 |
|
|
$ |
26.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
88.23 |
|
|
$ |
7.31 |
|
|
$ |
47.40 |
|
|
$ |
55.07 |
|
Cash settlements of hedges |
|
|
|
|
|
|
(0.04 |
) |
|
|
|
|
|
|
(0.14 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
88.23 |
|
|
$ |
7.27 |
|
|
$ |
47.40 |
|
|
$ |
54.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In the first quarter of 2009, our derivative financial instruments were comprised of gas price
collars. In the first quarter of 2008, our derivative financial instruments included gas price
swaps and oil and gas price collars. For the price swaps, we receive a fixed price for our
production and pay a variable market price to the contract counterparty. The price collars set a
floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by
the floor and ceiling prices in the various collars, we cash-settle the difference with the
counterparty to the collars. Cash settlements as presented in the tables above represent realized
losses or gains related to our price swaps and collars.
During the first quarter of 2009, we received $118 million, or $0.48 per Mcf from
counterparties to settle our gas price collars. During the first quarter of 2008, we paid $8
million, or $0.04 per Mcf, to 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 our gas
price collars at March 31, 2009, a 10% increase in these forward curves would have decreased our
first quarter 2009 unrealized gain for our gas collar derivative financial instruments by
approximately $29 million. Another key input to our cash flow calculations is our estimate of
volatility for these forward curves, which we base primarily upon implied volatility.
Counterparty credit risk is also a component of commodity derivative valuations. We have
mitigated our exposure to any single counterparty by contracting with numerous counterparties. Our
commodity derivative contracts are held with eight separate counterparties. Additionally, our
derivative contracts generally require cash collateral to be posted if either our or the
counterpartys credit rating falls below investment grade. The threshold for collateral posting
decreases as the debt rating falls further below investment grade. Such thresholds generally range
from zero to $50 million for the majority of our contracts. As of March 31, 2009, the credit
ratings of all our counterparties were investment grade.
During the first quarter of 2009, we recognized a $36 million unrealized gain as a result of
decreases in the Inside FERC Henry Hub forward curve subsequent to December 31, 2008.
During the first quarter of 2008, we recognized unrealized losses totaling $779 million
related to our gas derivative instruments. These losses resulted primarily from a significant
increase in the Inside FERC Henry Hub forward curve subsequent to our contract trade dates.
28
Marketing and Midstream Revenues and Operating Costs and Expenses
The details of the changes in marketing and midstream revenues, operating costs and expenses
and the resulting operating profit between the three months ended March 31, 2009 and 2008 are shown
in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
|
|
|
|
Marketing and midstream: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
371 |
|
|
$ |
555 |
|
|
|
-33 |
% |
Operating costs and expenses |
|
|
229 |
|
|
|
382 |
|
|
|
-40 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
142 |
|
|
$ |
173 |
|
|
|
-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. |
During the first quarter of 2009, marketing and midstream revenues decreased $184 million and
operating costs and expenses also decreased $153 million, causing operating profit to decrease $31
million. Revenues and expenses decreased primarily due to lower natural gas and NGL prices,
partially offset by increased gas pipeline throughput.
Oil, Gas and NGL Production and Operating Expenses
The details of the changes in oil, gas and NGL production and operating expenses between the
three months ended March 31, 2009 and 2008 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
|
|
|
|
Production and operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
524 |
|
|
$ |
506 |
|
|
|
+4 |
% |
Production taxes |
|
|
42 |
|
|
|
134 |
|
|
|
-68 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses |
|
$ |
566 |
|
|
$ |
640 |
|
|
|
-12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
8.50 |
|
|
$ |
8.69 |
|
|
|
-2 |
% |
Production taxes |
|
|
0.69 |
|
|
|
2.30 |
|
|
|
-70 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses per Boe |
|
$ |
9.19 |
|
|
$ |
10.99 |
|
|
|
-16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
Lease Operating Expenses (LOE)
LOE increased $18 million in the first quarter of 2009. LOE increased $29 million due to our
6% growth in production. Higher per-unit costs associated with our thermal heavy oil production
from our Jackfish operations in Canada and new oil production from Brazil caused LOE to increase an
additional $24 million. Until these large-scale projects reach their target full-scale production
levels, their per-unit operating costs will be higher than the per-unit costs for our overall
portfolio of producing properties. LOE also increased $7 million due to additional costs associated
with damages of certain of our facilities and transportation systems that were caused by Hurricane
Ike in the third quarter of 2008. These increases were partially offset by the effects of changes
in the exchange rate between the U.S. and Canadian dollar. The exchange rate caused LOE to decrease
$43 million and was the main contributor to the decrease in LOE per Boe.
Production Taxes
The following table details the changes in production taxes between the three months ended
March 31, 2009 and 2008. The majority of our production taxes are assessed on our U.S. onshore
properties and are based on a fixed percentage of revenues. Production taxes are also assessed on
certain of our International properties based on a variable percentage of revenues that generally
moves in tandem with commodity prices. 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 and
International properties.
29
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
(In millions) |
|
2008 production taxes |
|
$ |
134 |
|
Change due to revenues |
|
|
(71 |
) |
Change due to rate |
|
|
(21 |
) |
|
|
|
|
2009 production taxes |
|
$ |
42 |
|
|
|
|
|
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 months ended March 31, 2009 and 2008 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change(1) |
|
Total production volumes (MMBoe) |
|
|
62 |
|
|
|
58 |
|
|
|
+6 |
% |
DD&A rate ($ per Boe) |
|
$ |
9.72 |
|
|
$ |
12.64 |
|
|
|
-23 |
% |
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
599 |
|
|
$ |
737 |
|
|
|
-19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
The following table details the changes in DD&A of oil and gas properties between the three
months ended March 31, 2009 and 2008.
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
(In millions) |
|
2008 DD&A |
|
$ |
737 |
|
Change due to volumes |
|
|
42 |
|
Change due to rate |
|
|
(180 |
) |
|
|
|
|
2009 DD&A |
|
$ |
599 |
|
|
|
|
|
The 6% production increase during the first quarter of 2009 caused oil and gas property
related DD&A to increase $42 million. Oil and gas property-related DD&A decreased $180 million due
to a 23% decrease in the DD&A rate. The largest contributors to the rate decrease were reductions
of the carrying values of certain of our oil and gas properties recognized in the fourth quarter of
2008. These reductions totaled $10.4 billion and resulted from full cost ceiling limitations. In
addition, the effects of changes in the exchange rate between the U.S. and Canadian dollar
contributed to the rate decrease. These decreases were offset by the effects of inflationary
pressure on costs incurred during most of 2008 and the transfer of previously unproved costs to the
depletable base as a result of drilling activities.
General and Administrative Expenses (G&A)
The following schedule includes the components of G&A expense for the three-month periods
ended March 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
Change (1) |
|
|
|
(In millions) |
|
|
|
|
|
Gross G&A |
|
$ |
305 |
|
|
$ |
277 |
|
|
|
+10 |
% |
Capitalized G&A |
|
|
(104 |
) |
|
|
(99 |
) |
|
|
+5 |
% |
Reimbursed G&A |
|
|
(35 |
) |
|
|
(30 |
) |
|
|
+17 |
% |
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
166 |
|
|
$ |
148 |
|
|
|
+12 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are not
calculated using the rounded figures included in this table. |
30
Gross G&A increased $28 million in the first quarter of 2009 compared to the same period of
2008. The largest contributor to the increase was higher employee compensation and benefits costs,
which were largely related to growth and industry inflation experienced during most of 2008. The
increase in employee compensation and benefits caused gross G&A to increase $15 million. Employee
severance costs also increased, contributing to the increase in gross G&A.
Interest Expense
The following schedule includes the components of interest expense for the three-month periods
ended March 31, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
108 |
|
|
$ |
126 |
|
Capitalized interest |
|
|
(27 |
) |
|
|
(31 |
) |
Other |
|
|
2 |
|
|
|
7 |
|
|
|
|
|
|
|
|
Total |
|
$ |
83 |
|
|
$ |
102 |
|
|
|
|
|
|
|
|
Interest based on debt outstanding decreased during the first quarter of 2009 primarily due to
a decrease in outstanding borrowings. In the second quarter of 2008, we used proceeds from our West
African divestiture program and cash flow from operations to repay commercial paper and credit
facility borrowings. As a result, we had lower commercial paper and credit facility borrowings in
2009 than in 2008. Additionally, we retired our exchangeable debentures during the third quarter of
2008. These decreases were partially offset by interest related to the $500 million of 5.625%
senior unsecured notes and $700 million of 6.30% senior unsecured notes that we issued in January
2009.
Change in Fair Value of Other Financial Instruments
The details of the changes in fair value of other financial instruments for the three months
ended March 31, 2009 and 2008 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
(Gains) losses from: |
|
|
|
|
|
|
|
|
Interest rate swaps settlements |
|
$ |
(16 |
) |
|
$ |
|
|
Interest rate swaps fair value changes |
|
|
11 |
|
|
|
|
|
Chevron common stock |
|
|
|
|
|
|
113 |
|
Option embedded in exchangeable debentures |
|
|
|
|
|
|
(97 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
(5 |
) |
|
$ |
16 |
|
|
|
|
|
|
|
|
Interest Rate Swaps
During the first quarter of 2009, we received cash settlements totaling $16 million from
counterparties to settle our interest rate swaps. We also recognize unrealized changes in the fair
values of our interest rate swaps each reporting period. In the first quarter of 2009, we recorded
an $11 million unrealized fair value loss as a result of changes in interest rates subsequent to
December 31, 2008.
We estimate the fair values of our interest rate swap financial instruments primarily by using
internal discounted cash flow calculations based upon forward interest-rate yields. We periodically
validate our valuation techniques by comparing our internally generated fair value estimates with
those obtained from contract counterparties or brokers.
The most significant variable to our cash flow calculations is our estimate of future interest
rate yields. We base our estimate of future yields upon our own internal model that utilizes
forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the
notional amount subject to the interest rate swaps at March 31, 2009, a 10% increase in these
forward curves would have increased our first quarter 2009 unrealized loss for our interest rate
swaps by approximately $6 million.
31
As previously discussed for our commodity derivative contracts, counterparty credit risk is
also a component of interest rate derivative valuations. We have mitigated our exposure to any
single counterparty by contracting with several counterparties. Our interest rate derivative
contracts are held with five separate counterparties and have cash collateral posting requirements.
Additionally, the credit ratings of all our counterparties were investment grade as of March 31,
2009.
Chevron Common Stock and Related Embedded Option
The 2008 loss on our investment in Chevron common stock and gain on the embedded option were
directly attributable to a $7.97 per share decrease of Chevrons common stock during the first
quarter of 2008. The Chevron common stock was exchanged for Chevrons interest in certain oil and
gas properties and cash in the fourth quarter of 2008. The exchangeable debentures were retired in
August 2008.
Reduction of Carrying Value of Oil and Gas Properties
In the first quarter of 2009, we reduced the carrying values of certain of our oil and gas
properties due to full cost ceiling limitations. A summary of these reductions and additional
discussion is provided below.
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
|
|
|
|
|
|
Net of |
|
|
|
Gross |
|
|
Taxes |
|
|
|
(In millions) |
|
United States |
|
$ |
6,408 |
|
|
$ |
4,085 |
|
Brazil |
|
|
103 |
|
|
|
103 |
|
Russia |
|
|
5 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Total |
|
$ |
6,516 |
|
|
$ |
4,190 |
|
|
|
|
|
|
|
|
The United States reduction resulted primarily from a significant decrease in the full cost
ceiling during the first three months of 2009. The lower ceiling value in the United States largely
resulted from the continued effects of declining natural gas prices subsequent to December 31,
2008.
Although oil prices improved subsequent to December 31, 2008, Brazils reduction resulted
largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin.
After drilling this well in the first quarter of 2009, we concluded that the well did not have
adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs
associated with this well contributed to the reduction recognized in the first quarter of 2009.
To demonstrate the changes in the full-cost ceiling for the United States and Brazil, the
March 31, 2009 and December 31, 2008 weighted average wellhead prices are presented in the
following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2009 |
|
December 31, 2008 |
|
|
Oil |
|
Gas |
|
NGLs |
|
Oil |
|
Gas |
|
NGLs |
Country |
|
(Per Bbl) |
|
(Per Mcf) |
|
(Per Bbl) |
|
(Per Bbl) |
|
(Per Mcf) |
|
(Per Bbl) |
United States |
|
$ |
47.30 |
|
|
$ |
2.67 |
|
|
$ |
17.04 |
|
|
$ |
42.21 |
|
|
$ |
4.68 |
|
|
$ |
16.16 |
|
Brazil |
|
$ |
36.71 |
|
|
|
N/A |
|
|
|
N/A |
|
|
$ |
26.61 |
|
|
|
N/A |
|
|
|
N/A |
|
The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash
price of $49.66 per Bbl for crude oil and the Henry hub spot price of $3.63 per MMBtu for gas. The
December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of
$44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas.
32
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 periods ended March 31, 2009 and 2008. The primary factors causing our effective rates
to vary from 2008 to 2009, and differ from the U.S. statutory rate, are discussed below.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
Total income tax (benefit) expense (In millions) |
|
$ |
(2,269 |
) |
|
$ |
241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
|
(35 |
%) |
|
|
35 |
% |
Canadian statutory rate reductions |
|
|
|
|
|
|
(1 |
%) |
Other, primarily taxation on foreign operations |
|
|
(1 |
%) |
|
|
(7 |
%) |
|
|
|
|
|
|
|
Effective income tax rate |
|
|
(36 |
%) |
|
|
27 |
% |
|
|
|
|
|
|
|
In the first quarter of 2009, our effective tax rate was impacted by the reductions of
carrying value that totaled $6.5 billion and had associated deferred tax benefits of $2.3 billion.
Excluding the effects of these reductions, our effective tax rate was 19%. This rate and the 2008
rate 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. Additionally, in the
first quarter of 2008 deferred taxes were reduced by $7 million due to statutory rate reductions
enacted by the British Columbia and Saskatchewan provincial governments in Canada.
Capital Resources, Uses and Liquidity
The following discussion of capital resources and liquidity should be read in conjunction with
the consolidated statements of cash flows included in Part I, Item 1.
Sources and Uses of Cash
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
1,042 |
|
|
$ |
2,070 |
|
Commercial paper borrowings |
|
|
894 |
|
|
|
|
|
Proceeds from debt issuance, net of commercial paper repayments |
|
|
182 |
|
|
|
|
|
Sales of property and equipment |
|
|
1 |
|
|
|
105 |
|
Stock option exercises |
|
|
4 |
|
|
|
74 |
|
Net sales of long-term and short-term investments |
|
|
2 |
|
|
|
220 |
|
Other |
|
|
2 |
|
|
|
27 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
2,127 |
|
|
|
2,496 |
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(2,019 |
) |
|
|
(1,862 |
) |
Repayments of debt |
|
|
(1 |
) |
|
|
(129 |
) |
Repurchases of common stock |
|
|
|
|
|
|
(64 |
) |
Dividends |
|
|
(70 |
) |
|
|
(73 |
) |
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(2,090 |
) |
|
|
(2,128 |
) |
|
|
|
|
|
|
|
Increase from continuing operations |
|
|
37 |
|
|
|
368 |
|
(Decrease) increase from discontinued operations |
|
|
(9 |
) |
|
|
161 |
|
Effect of foreign exchange rates |
|
|
(11 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
Net increase in cash and cash equivalents |
|
$ |
17 |
|
|
$ |
510 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
401 |
|
|
$ |
1,883 |
|
|
|
|
|
|
|
|
33
Operating Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash flow) continued to be a
significant source of capital and liquidity in the first three months of 2009. Changes in operating
cash flow are largely due to the same factors that affect our net earnings, with the exception of
those earnings changes due to noncash expenses such as DD&A, property impairments, financial
instrument fair value changes and deferred income taxes. Our operating cash flow decreased in 2009
primarily due to the decrease in revenues as discussed in the Results of Operations section of
this report.
During the first three months of 2009, our operating cash flow funded approximately half of
our cash payments for capital expenditures. Commercial paper borrowings were used to fund the
remainder of our cash-based capital expenditures. During the first three months of 2008, our
operating cash flow was sufficient to fund our cash payments for capital expenditures.
Other Sources of Cash
As needed, we utilize cash on hand and access our available credit under our credit facilities
and commercial paper program as sources of cash to supplement our operating cash flow. We may also
issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity
under our credit facilities. 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.
In January 2009, we issued $500 million of 5.625% senior unsecured notes due January 15, 2014
and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of
$1.187 billion, after discounts and issuance costs, were used primarily to repay Devons $1.0
billion of outstanding commercial paper as of December 31, 2008.
Subsequent to the $1.0 billion commercial paper repayment in January 2009, we utilized
additional commercial paper borrowings of $894 million to fund capital expenditure payments in
excess of first quarter operating cash flow.
Capital Expenditures
Following are the components of our capital expenditures for the first quarters of 2009 and
2008. The amounts in the table below reflect cash payments for capital expenditures, including cash
paid for capital expenditures incurred in prior quarters. Capital expenditures actually incurred
during the first quarters of 2009 and 2008 were approximately $1.5 billion and $2.0 billion,
respectively.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
1,107 |
|
|
$ |
959 |
|
U.S. Offshore |
|
|
333 |
|
|
|
244 |
|
Canada |
|
|
327 |
|
|
|
415 |
|
International |
|
|
90 |
|
|
|
110 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
1,857 |
|
|
|
1,728 |
|
Midstream |
|
|
128 |
|
|
|
104 |
|
Other |
|
|
34 |
|
|
|
30 |
|
|
|
|
|
|
|
|
Total cash paid for capital expenditures |
|
$ |
2,019 |
|
|
$ |
1,862 |
|
|
|
|
|
|
|
|
Our capital expenditures consist of amounts related to our oil and gas exploration and
development operations, our midstream operations and other corporate activities. The vast majority
of our capital expenditures are for the acquisition, drilling or development of oil and gas
properties, which totaled $1.9 billion and $1.7 billion in the first quarters of 2009 and 2008,
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. As
we scale back our drilling activities in response to the decline in our operating cash flow,
capital expenditures for exploration, development and midstream activities are expected to be lower
in each of the remaining 2009 quarters compared to the first quarter.
Our exploration and development capital expenditures increased $129 million in the first
quarter of 2009. The higher expenditures primarily related to an increase in cash payments
associated with drilling activities in the Barnett Shale and Gulf of Mexico.
34
Repayments of Debt
During the first quarter of 2008, we reduced our credit facility and commercial paper
borrowings by $88 million. Also during the first quarter of 2008, certain holders of exchangeable
debentures exercised their option to exchange their debentures for shares of Chevron common stock
prior to the debentures August 15, 2008 maturity date. In lieu of delivering shares of Chevron
common stock we owned, we exercised our option to pay exchanging debenture holders cash equal to
the market value of Chevron common stock. We paid $41 million in cash to debenture holders who
exercised their exchange rights in the first quarter of 2008. This amount included the retirement
of debentures with a book value of $25 million and a $16 million reduction of the related embedded
derivative options balance.
Repurchases of Common Stock
During the first quarter of 2008, we repurchased 0.8 million shares at a cost of $64 million.
Dividends
Our common stock dividends were $70 million and $71 million (quarterly rates of $0.16 per
share) in the first quarter of 2009 and 2008, respectively. Our preferred dividends were $2 million
in the first quarter of 2008. 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 historically been our operating cash flow and
cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program
that can be accessed as needed to supplement operating cash flow. Other available sources of
capital and liquidity include the issuance of equity securities and long-term debt. We estimate
these capital resources will provide sufficient liquidity to fund our planned uses of capital.
Operating Cash Flow
Our operating cash flow is sensitive to many variables, the most volatile of which is pricing
of the oil, natural gas and NGLs we produce. Due to sharp declines in commodity prices, our
operating cash flow decreased 54% to $1.0 billion in the first quarter of 2009 compared to the
first quarter of 2008. In spite of this decline, we expect operating cash flow will continue to be
a primary source of liquidity. However, based on current commodity prices and near-term price
expectations, we also expect that debt borrowings will be a significant source of liquidity during
2009. During the first quarter of 2009, our net borrowings of long-term debt and commercial paper
totaled $1.1 billion. We anticipate we will borrow additional commercial paper during 2009 to
assist in funding our capital expenditures and other capital uses.
Credit Lines
As of April 30, 2009, we had $2.2 billion of available capacity under our credit facilities
that can be used to supplement our operating cash flow and cash on hand to fund our capital
expenditures and other commitments. The following schedule summarizes the capacity of our credit
facilities by maturity date, as well as our available capacity as of April 30, 2009.
|
|
|
|
|
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 November 3, 2009
maturity |
|
|
700 |
|
|
|
|
|
Total credit facility capacity |
|
|
3,350 |
|
Less: |
|
|
|
|
Outstanding credit facility borrowings |
|
|
|
|
Outstanding commercial paper borrowings |
|
|
997 |
|
Outstanding letters of credit |
|
|
111 |
|
|
|
|
|
Total available capacity |
|
$ |
2,242 |
|
|
|
|
|
35
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 March 31, 2009, Devon was in compliance with this covenant.
Devons debt-to-capitalization ratio at March 31, 2009, as calculated pursuant to the terms of the
agreement, was 21.3%.
Capital Expenditures
In February 2009, we provided guidance for our 2009 capital expenditures. At that time, we
estimated total capital expenditures would range from $4.7 billion to $5.4 billion. This estimate
is significantly lower than our 2008 capital expenditures, which coincides with the significant
decline in current oil, gas and NGL prices, as well as the near-term price expectations. Based upon
current oil and natural gas price expectations, we anticipate having adequate capital resources to
fund this planned level of 2009 capital expenditures.
Recently Issued Accounting Standards Not Yet Adopted
In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers Disclosures
about Postretirement Benefit Plan Assets. Staff Position 132(R)-1 amends FASB Statement No. 132
(revised 2003), Employers Disclosures about Pensions and Other Postretirement Benefits, to require
additional disclosures about the types of assets and associated risks in an employers defined
benefit pension or other postretirement plan. Staff Position 132(R)-1 is effective for fiscal years
ending after December 15, 2009. We are evaluating the impact the adoption of Staff Position
132(R)-1 will have on our financial statement disclosures. However, our adoption of Staff Position
132(R)-1 will not affect our current accounting for our pension and postretirement plans.
Modernization of Oil and Gas Reporting
In December 2008, the SEC adopted revisions to its required oil and gas reporting disclosures.
The revisions are intended to provide investors with a more meaningful and comprehensive
understanding of oil and gas reserves. In the three decades that have passed since adoption of
these disclosure items, there have been significant changes in the oil and gas industry. The
amendments are designed to modernize and update the oil and gas disclosure requirements to align
them with current practices and changes in technology. In addition, the amendments concurrently
align the SECs full cost accounting rules with the revised disclosures. The revised disclosure
requirements must be incorporated in registration statements filed on or after January 1, 2010, and
annual reports on Form 10-K for fiscal years ending on or after December 31, 2009. A company may
not apply the new rules to disclosures in quarterly reports prior to the first annual report in
which the revised disclosures are required.
The following amendments have the greatest likelihood of affecting our reserve disclosures,
including the comparability of our reserves disclosures with those of our peer companies:
|
|
|
Pricing mechanism for oil and gas reserves estimation The SECs current rules require
proved reserve estimates to be calculated using prices as of the end of the period and held
constant over the life of the reserves. Price changes can be made only to the extent
provided by contractual arrangements. The revised rules require reserve estimates to be
calculated using a 12-month average price. The 12-month average price will also be used for
purposes of calculating the full cost ceiling limitations. Price changes can still be
incorporated to the extent defined by contractual arrangements. The use of a 12-month
average price rather than a single-day price is expected to reduce the impact on reserve
estimates and the full cost ceiling limitations due to short-term volatility and seasonality
of prices. |
|
|
|
|
Reasonable certainty The SECs current definition of proved oil and gas reserves
incorporate certain specific concepts such as lowest known hydrocarbons, which limits the
ability to claim proved reserves in the absence of information on fluid contacts in a well
penetration, notwithstanding the existence of other engineering and geoscientific evidence.
The revised rules amend the definition to permit the use of new reliable technologies to
establish the reasonable certainty of proved reserves. This revision also includes
provisions for establishing levels of lowest known hydrocarbons and highest known oil
through reliable technology other than well penetrations. |
|
|
|
|
The revised rules also amend the definition of proved oil and gas reserves to include
reserves located beyond development spacing areas that are immediately adjacent to developed
spacing areas if economic producibility can be established with reasonable certainty. These
revisions are designed to permit the use of alternative technologies to establish proved
reserves in lieu of requiring companies to use specific tests. In addition, they establish a
uniform standard of reasonable certainty that applies to all proved reserves, regardless of
location or distance from producing wells. |
36
|
|
|
Because the revised rules generally expand the definition of proved reserves, we expect our
proved reserve estimates will increase upon adoption of the revised rules. However, we are
not able to estimate the magnitude of the potential increase at this time. |
|
|
|
|
Unproved reserves The SECs current rules prohibit disclosure of reserve estimates
other than proved in documents filed with the SEC. The revised rules permit disclosure of
probable and possible reserves and provide definitions of probable reserves and possible
reserves. Disclosure of probable and possible reserves is optional. However, such
disclosures must meet specific requirements. Disclosures of probable or possible reserves
must provide the same level of geographic detail as proved reserves and must state whether
the reserves are developed or undeveloped. Probable and possible reserve disclosures must
also provide the relative uncertainty associated with these classifications of reserves
estimations. We have not yet determined whether we will disclose our probable and possible
reserves in documents filed with the SEC. |
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have various financial price collars to set minimum and maximum prices on approximately 10%
of our 2009 gas production. The key terms to these 2009 price collars are included in Item 7A.
Quantitative and Qualitative Disclosures about Market Risk in our 2008 Annual Report on Form
10-K.
The fair values of our gas price collar hedging instruments are largely determined by
estimates of the forward curves of the Inside FERC Henry Hub index. At March 31, 2009, a 10%
increase in the Inside FERC Henry Hub index forward curves would have decreased the net assets
recorded for our gas price collar hedging instruments by approximately $29 million.
Interest Rate Risk
At March 31, 2009, we had debt outstanding of $6.9 billion. Of this amount, $6.0 billion, or
87%, bears interest at fixed rates averaging 7.2%. Additionally, we had $0.9 billion of outstanding
commercial paper, bearing interest at floating rates which averaged 0.7%.
We also have interest rate swaps to mitigate a portion of the fair value effects of interest
rate fluctuations on our fixed-rate debt. The key terms to these interest rate swaps are included
in Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our 2008 Annual Report
on Form 10-K. In addition, subsequent to the preparation of our 2008 Annual Report on Form 10-K, we
entered into additional interest rate swaps that have a total notional value of $200 million and
expire on September 30, 2011. The terms of these contracts specify that the swaps will be net
settled in September 2011. The net settlement amount will be based upon us paying a
weighted-average fixed rate of 3.55% and receiving a floating rate that is based upon the
three-month LIBOR forward curve. The difference between these fixed and floating rates will be
applied to the notional amount for the 30-year period from September 30, 2011 to September 30,
2041.
The fair values of our interest rate instruments are largely determined by estimates of the
forward curves of the Federal Funds Rate and LIBOR. At March 31, 2009, a 10% increase in these
forward curves would have increased our net assets recorded for our interest rate derivative
instruments by approximately $6 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 March 31, 2009 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.
37
Changes in Internal Control Over Financial Reporting
There was no change in Devons internal control over financial reporting during the first
quarter of 2009 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
38
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 2008 Annual Report on Form 10-K.
Item 1A. Risk Factors
There have been no material changes to the information included in Item 1A. Risk Factors in
our 2008 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
No shares have been repurchased during the first quarter of 2009.
As of March 31, 2009, we are authorized to repurchase 50.3 million shares. This amount is
comprised of 45.5 million remaining shares authorized to be repurchased under a 50 million share
repurchase program and 4.8 million shares authorized to be repurchased in 2009 under an annual
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.
Item 6. Exhibits
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
|
|
|
Exhibit |
|
|
Number |
|
Description |
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. |
39
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
|
DEVON ENERGY CORPORATION |
|
|
|
|
|
Date: May 7, 2009 |
/s/ Danny J. Heatly
|
|
|
Danny J. Heatly |
|
|
Senior Vice President Accounting and Chief Accounting Officer |
|
40
INDEX TO EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Description |
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. |
41