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, 2008
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File No. 001-32318
Devon Energy Corporation
(Exact Name of Registrant as Specified in its Charter)
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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73-1567067
(I.R.S. Employer
Identification Number) |
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20 North Broadway
Oklahoma City, Oklahoma
(Address of Principal Executive Offices)
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73102-8260
(Zip Code) |
Registrants telephone number, including area code:
(405) 235-3611
Former name, former address and former fiscal year, if changed from last report.
Not applicable
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
As of April 30, 2008, 446,162,105 shares of the registrants common stock were outstanding.
[This page intentionally left blank.]
2
DEVON ENERGY CORPORATION
INDEX TO FORM 10-Q QUARTERLY REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
3
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements other than statements of historical facts included or incorporated by
reference in this report, including, without limitation, statements regarding our future financial
position, business strategy, budgets, projected revenues, projected costs and plans and objectives
of management for future operations, are forward-looking statements. Such forward-looking
statements are based on our examination of historical operating trends, the information that was
used to prepare the December 31, 2007 reserve reports and other data in our possession or available
from third parties. In addition, forward-looking statements generally can be identified by the use
of forward-looking terminology such as may, will, expect, intend, project, estimate,
anticipate, believe, or continue or similar terminology. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can give no assurance
that such expectations will prove to have been correct. Important factors that could cause actual
results to differ materially from our expectations include, but are not limited to, our assumptions
about:
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energy markets; |
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production levels, including our Canadian production subject to government royalties,
which fluctuate with prices and production, and portions of our International production
governed by payout agreements which affect reported production; |
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reserve levels; |
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competitive conditions; |
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technology; |
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the availability of capital resources; |
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capital expenditure and other contractual obligations; |
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the supply and demand for oil, natural gas, NGLs and other energy products or
services; |
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the price of oil, natural gas, NGLs and other energy products or services; |
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currency exchange rates, particularly the Canadian-to-U.S. dollar exchange rate; |
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the weather; |
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inflation; |
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the availability of goods and services; |
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drilling risks; |
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future processing volumes and pipeline throughput; |
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general economic conditions, whether internationally, nationally or in the
jurisdictions in which we or our subsidiaries conduct business; |
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legislative or regulatory changes, including retroactive royalty or production tax
regimes, changes in environmental regulation, environmental risks and liability under
federal, state and foreign environmental laws and regulations; |
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terrorism; |
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occurrence of property acquisitions or divestitures or the timing of such planned
transactions; |
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the securities or capital markets and related risks such as general credit,
liquidity, market and interest-rate risks; and |
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other factors disclosed in Devons 2007 Annual Report on Form 10-K under Item 2.
Properties Proved Reserves and Estimated Future Net Revenue, Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations, and Item 7A.
Quantitative and Qualitative Disclosures About Market Risk. |
All subsequent written and oral forward-looking statements attributable to Devon, or persons
acting on its
behalf, are expressly qualified in their entirety by the cautionary statements. We assume no
duty to update or revise
our forward-looking statements based on changes in internal estimates or
expectations or otherwise.
4
DEFINITIONS
AS USED IN THIS DOCUMENT:
Bbl or Bbls means barrel or barrels.
Bcf means billion cubic feet.
Boe means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs
to six Mcf of gas.
Btu means British thermal units, a measure of heating value.
Inside FERC refers to the publication Inside F.E.R.C.s Gas Market Report.
Mcf means thousand cubic feet.
MMBbls means million barrels.
MMBoe means million Boe.
MMBtu means million Btu.
Oil includes crude oil and condensate.
NGL or NGLs means natural gas liquids.
NYMEX means New York Mercantile Exchange.
SEC means United States Securities and Exchange Commission.
Domestic means the properties of Devon in the onshore continental United States and the
offshore Gulf of Mexico.
Canada means the division of Devon encompassing oil and gas properties located in Canada.
International means the division of Devon encompassing oil and gas properties that lie
outside the United States and Canada.
5
PART I. Financial Information
Item 1. Consolidated Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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March 31, |
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December 31, |
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2008 |
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2007 |
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(Unaudited) |
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(In millions, except share data) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
1,875 |
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$ |
1,364 |
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Short-term investments, at fair value |
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23 |
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372 |
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Accounts receivable |
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2,090 |
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1,779 |
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Deferred income taxes |
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325 |
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44 |
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Current assets held for sale |
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112 |
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120 |
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Other current assets |
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232 |
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235 |
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Total current assets |
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4,657 |
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3,914 |
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Property and equipment, at cost, based on the full cost method of accounting
for oil and gas properties ($3,492 and $3,417 excluded from amortization
in 2008 and 2007, respectively) |
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49,816 |
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48,473 |
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Less accumulated depreciation, depletion and amortization |
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20,883 |
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20,394 |
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28,933 |
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28,079 |
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Investment in Chevron Corporation common stock, at fair value |
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1,211 |
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1,324 |
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Goodwill |
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6,054 |
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6,172 |
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Long-term assets held for sale |
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1,531 |
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1,512 |
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Other long-term assets |
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599 |
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455 |
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Total assets |
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$ |
42,985 |
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$ |
41,456 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable trade |
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$ |
1,440 |
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$ |
1,360 |
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Revenues and royalties due to others |
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695 |
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578 |
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Short-term debt |
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1,446 |
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1,004 |
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Derivative financial instruments, at fair value |
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775 |
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Current portion of asset retirement obligation, at fair value |
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68 |
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82 |
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Current liabilities associated with assets held for sale |
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173 |
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145 |
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Accrued expenses and other current liabilities |
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398 |
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488 |
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Total current liabilities |
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4,995 |
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3,657 |
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Debentures exchangeable into shares of Chevron Corporation common stock |
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620 |
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641 |
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Other long-term debt |
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5,751 |
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6,283 |
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Derivative financial instruments, at fair value |
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376 |
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488 |
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Asset retirement obligation, at fair value |
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1,377 |
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1,236 |
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Long-term liabilities associated with assets held for sale |
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428 |
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404 |
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Other long-term liabilities |
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701 |
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699 |
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Deferred income taxes |
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6,339 |
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6,042 |
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Stockholders equity: |
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Preferred stock of $1.00 par value. Authorized 4,500,000 shares;
issued 1,500,000 ($150 million aggregate liquidation value) |
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1 |
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1 |
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Common stock of $0.10 par value. Authorized 800,000,000 shares;
issued 445,645,000 in 2008 and 444,214,000 in 2007 |
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45 |
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44 |
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Additional paid-in capital |
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6,820 |
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6,743 |
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Retained earnings |
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13,489 |
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12,813 |
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Accumulated other comprehensive income |
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2,043 |
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2,405 |
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Total stockholders equity |
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22,398 |
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22,006 |
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Commitments and contingencies (Note 8) |
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Total liabilities and stockholders equity |
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$ |
42,985 |
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$ |
41,456 |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months |
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Ended March 31, |
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2008 |
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2007 |
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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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$ |
1,250 |
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$ |
691 |
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Gas sales |
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1,630 |
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1,246 |
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NGL sales |
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328 |
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177 |
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Net loss on oil and gas derivative financial instruments |
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(788 |
) |
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(20 |
) |
Marketing and midstream revenues |
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555 |
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379 |
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Total revenues |
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2,975 |
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2,473 |
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Expenses and other income, net: |
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Lease operating expenses |
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506 |
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430 |
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Production taxes |
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134 |
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80 |
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Marketing and midstream operating costs and expenses |
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382 |
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270 |
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Depreciation, depletion and amortization of oil and gas properties |
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737 |
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587 |
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Depreciation and amortization of non-oil and gas properties |
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57 |
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46 |
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Accretion of asset retirement obligation |
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22 |
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18 |
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General and administrative expenses |
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148 |
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119 |
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Interest expense |
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102 |
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110 |
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Change in fair value of non-oil and gas derivative financial instruments |
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16 |
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1 |
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Other income, net |
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(21 |
) |
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(26 |
) |
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Total expenses and other income, net |
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2,083 |
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1,635 |
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Earnings from continuing operations before income tax expense |
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892 |
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838 |
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Income tax expense: |
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Current |
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103 |
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189 |
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Deferred |
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138 |
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75 |
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Total income tax expense |
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241 |
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264 |
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Earnings from continuing operations |
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651 |
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574 |
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Discontinued operations: |
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Earnings from discontinued operations before income tax expense |
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189 |
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137 |
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Income tax expense |
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91 |
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60 |
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Earnings from discontinued operations |
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98 |
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77 |
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Net earnings |
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749 |
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651 |
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Preferred stock dividends |
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2 |
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2 |
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Net earnings applicable to common stockholders |
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$ |
747 |
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$ |
649 |
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Basic net earnings per share: |
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Earnings from continuing operations |
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$ |
1.46 |
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$ |
1.29 |
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Earnings from discontinued operations |
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0.22 |
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0.17 |
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Net earnings |
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$ |
1.68 |
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$ |
1.46 |
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Diluted net earnings per share: |
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Earnings from continuing operations |
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$ |
1.44 |
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$ |
1.27 |
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Earnings from discontinued operations |
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0.22 |
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0.17 |
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Net earnings |
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$ |
1.66 |
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$ |
1.44 |
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Weighted average common shares outstanding: |
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Basic |
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445 |
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444 |
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Diluted |
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449 |
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|
450 |
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See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
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Three Months |
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Ended March 31, |
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2008 |
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2007 |
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(Unaudited) |
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(In millions) |
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Net earnings |
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$ |
749 |
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$ |
651 |
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Foreign currency translation: |
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Change in cumulative translation adjustment |
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(382 |
) |
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83 |
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Income tax benefit (expense) |
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17 |
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(6 |
) |
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Total |
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(365 |
) |
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77 |
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Pension and postretirement benefit plans: |
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Recognition of net actuarial loss and prior service cost in net earnings |
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5 |
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4 |
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Income tax expense |
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(2 |
) |
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(1 |
) |
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Total |
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3 |
|
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|
3 |
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|
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Other |
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(1 |
) |
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Other comprehensive (loss) income, net of tax |
|
|
(362 |
) |
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|
79 |
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Comprehensive income |
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$ |
387 |
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|
$ |
730 |
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|
|
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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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|
|
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|
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Additional |
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Other |
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Total |
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Preferred |
|
|
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 |
|
|
Stock |
|
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Equity |
|
|
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(Unaudited) |
|
|
|
(In millions) |
|
Three Months Ended March 31, 2008: |
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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 |
|
Excess tax benefits on share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2008 |
|
$ |
1 |
|
|
|
446 |
|
|
$ |
45 |
|
|
$ |
6,820 |
|
|
$ |
13,489 |
|
|
$ |
2,043 |
|
|
$ |
|
|
|
$ |
22,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006 |
|
$ |
1 |
|
|
|
444 |
|
|
$ |
44 |
|
|
$ |
6,840 |
|
|
$ |
9,114 |
|
|
$ |
1,444 |
|
|
$ |
(1 |
) |
|
$ |
17,442 |
|
Adoption of FASB Statement No. 159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
364 |
|
|
|
(364 |
) |
|
|
|
|
|
|
|
|
Adoption of FASB Interpretation No. 48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
651 |
|
|
|
|
|
|
|
|
|
|
|
651 |
|
Other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
79 |
|
|
|
|
|
|
|
79 |
|
Stock option exercises |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
Common stock retired |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(62 |
) |
|
|
|
|
|
|
|
|
|
|
(62 |
) |
Preferred stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30 |
|
Excess tax benefits on share-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2007 |
|
$ |
1 |
|
|
|
445 |
|
|
$ |
44 |
|
|
$ |
6,897 |
|
|
$ |
10,055 |
|
|
$ |
1,159 |
|
|
$ |
|
|
|
$ |
18,156 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
749 |
|
|
$ |
651 |
|
Earnings from discontinued operations, net of tax |
|
|
(98 |
) |
|
|
(77 |
) |
Adjustments to reconcile earnings from continuing operations
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
794 |
|
|
|
633 |
|
Deferred income tax expense |
|
|
138 |
|
|
|
75 |
|
Net unrealized loss on oil and gas derivative financial instruments |
|
|
780 |
|
|
|
32 |
|
Other noncash charges |
|
|
74 |
|
|
|
43 |
|
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Increase in: |
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(328 |
) |
|
|
(29 |
) |
Other current assets |
|
|
(39 |
) |
|
|
(10 |
) |
Other long-term assets |
|
|
(11 |
) |
|
|
(25 |
) |
Increase (decrease) in: |
|
|
|
|
|
|
|
|
Accounts payable |
|
|
38 |
|
|
|
66 |
|
Revenues and royalties due to others |
|
|
119 |
|
|
|
(46 |
) |
Other current liabilities |
|
|
(167 |
) |
|
|
89 |
|
Other long-term liabilities |
|
|
21 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
Cash provided by operating activities continuing operations |
|
|
2,070 |
|
|
|
1,400 |
|
Cash provided by operating activities discontinued operations |
|
|
185 |
|
|
|
117 |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
2,255 |
|
|
|
1,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Proceeds from sales of property and equipment |
|
|
105 |
|
|
|
25 |
|
Capital expenditures |
|
|
(1,862 |
) |
|
|
(1,484 |
) |
Purchases of short-term investments |
|
|
(50 |
) |
|
|
(424 |
) |
Sales of short-term investments |
|
|
270 |
|
|
|
723 |
|
|
|
|
|
|
|
|
Cash used in investing activities continuing operations |
|
|
(1,537 |
) |
|
|
(1,160 |
) |
Cash used in investing activities discontinued operations |
|
|
(24 |
) |
|
|
(53 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(1,561 |
) |
|
|
(1,213 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Credit facility repayments |
|
|
(1,450 |
) |
|
|
|
|
Credit facility borrowings |
|
|
920 |
|
|
|
|
|
Net commercial paper borrowings (repayments) |
|
|
442 |
|
|
|
(348 |
) |
Principal payments on debt |
|
|
(41 |
) |
|
|
|
|
Proceeds from stock option exercises |
|
|
74 |
|
|
|
23 |
|
Repurchases of common stock |
|
|
(64 |
) |
|
|
|
|
Dividends paid on common and preferred stock |
|
|
(73 |
) |
|
|
(64 |
) |
Excess tax benefits related to share-based compensation |
|
|
27 |
|
|
|
5 |
|
|
|
|
|
|
|
|
Net cash used in financing activities |
|
|
(165 |
) |
|
|
(384 |
) |
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
(19 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
510 |
|
|
|
(78 |
) |
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale) |
|
|
1,373 |
|
|
|
756 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash related
to assets held for sale) |
|
$ |
1,883 |
|
|
$ |
678 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data: |
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest) |
|
$ |
136 |
|
|
$ |
138 |
|
Income taxes paid (received) continuing and discontinued operations |
|
$ |
83 |
|
|
$ |
(24 |
) |
See accompanying notes to consolidated financial statements.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
The accompanying unaudited consolidated financial statements and notes of Devon Energy
Corporation (Devon) have been prepared pursuant to the rules and regulations of the United States
Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures
normally included in financial statements prepared in accordance with accounting principles
generally accepted in the United States of America have been omitted. The accompanying consolidated
financial statements and notes should be read in conjunction with the consolidated financial
statements and notes included in Devons 2007 Annual Report on Form 10-K.
The unaudited interim consolidated financial statements furnished in this report reflect all
adjustments which are, in the opinion of management, necessary to a fair statement of Devons
financial position as of March 31, 2008 and Devons results of operations and cash flows for the
three months ended March 31, 2008 and 2007. Except for the reclassification of auction rate
securities discussed below, all such adjustments are of a normal recurring nature.
Reclassification of Auction Rate Securities
At December 31, 2007, Devon held $372 million of auction rate securities. Such securities are
rated AAAthe highest ratingby one or more rating agencies and are collateralized by student
loans that are substantially guaranteed by the United States government. Although Devons auction
rate securities generally have contractual maturities of more than 20 years, the underlying
interest rates on such securities are scheduled to reset every seven to 28 days. Therefore, these
auction rate securities were generally priced and subsequently traded as short-term investments
because of the interest rate reset feature. As a result, Devon classified its auction rate
securities as short-term investments in the accompanying December 31, 2007 consolidated balance
sheet and in prior periods.
During the first quarter of 2008, Devon reduced its auction rate securities holdings to $152
million as of March 31, 2008. However, since February 8, 2008 Devon has experienced difficulty
selling its securities due to the failure of the auction mechanism, which provides liquidity to
these securities. An auction failure means that the parties wishing to sell securities could not do
so. The securities for which auctions have failed will continue to accrue interest and be auctioned
every seven to 28 days until the auction succeeds, the issuer calls the securities or the
securities mature.
Devons auction rate securities holdings as of March 31, 2008 include $23 million of
securities that have been called at par value by the issuer effective May 21, 2008. These called
securities continue to be classified as short-term investments in the accompanying March 31, 2008
consolidated balance sheet. However, based on continued auction failures and the current market for
Devons auction rate securities, Devon has classified the $129 million of securities that have not
been called as long-term investments as of March 31, 2008. Devon has the ability to hold the
securities until maturity. These securities are included in other long-term assets in the
accompanying March 31, 2008 consolidated balance sheet. At this time, Devon does not believe the
values of its long-term securities are impaired.
Recently Issued Accounting Standards Not Yet Adopted
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 141(R), Business Combinations, which replaces Statement No. 141.
Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be
identified and the acquisition method of accounting (previously called the purchase method) be used
for all business combinations. Statement No. 141(R)s scope is broader than that of Statement No.
141, which applied only to business combinations in which control was obtained by transferring
consideration. By applying the acquisition method to all transactions and other events in which one
entity obtains control over one or more other businesses, Statement No. 141(R) improves the
comparability of the information about business combinations provided in financial reports.
Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and
measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the
acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. Devon will evaluate how the new
requirements of Statement No. 141(R) would impact any business combinations completed in 2009 or
thereafter.
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160,
Noncontrolling Interests in Consolidated Financial Statementsan amendment of Accounting Research
Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of
equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160
establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a
subsidiary must be reported as a component of consolidated equity separate from the parents
equity. Additionally, the amounts of consolidated net income attributable to both the parent and
the noncontrolling interest must be reported separately on the face of the income statement.
Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier
adoption is prohibited. Devon does not expect the adoption of Statement No. 160 to have a material
impact on its financial statements and related disclosures.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,
Disclosures about Derivative Instruments and Hedging Activitiesan amendment of FASB Statement No.
133. Statement No. 161 requires additional disclosures about derivative and hedging activities and
is effective for fiscal years and interim periods beginning after November 15, 2008. Devon is
evaluating the impact the adoption of Statement No. 161 will have on its financial statement
disclosures. However, Devons adoption of Statement No. 161 will not affect its current accounting
for derivative and hedging activities.
2. Property and Equipment and Asset Retirement Obligations
Divestitures
Devon sold its assets and terminated its operations in Egypt in the fourth quarter of 2007.
Devon is also in the process of divesting its assets and terminating its operations in West Africa.
Additional information regarding Devons Egyptian and West African operations, which are presented
as discontinued in the accompanying financial statements, is provided in Note 10.
Asset Retirement Obligations (ARO)
The following is a summary of the changes in Devons ARO for the first three months of 2008
and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Asset retirement obligation as of beginning of period |
|
$ |
1,318 |
|
|
$ |
857 |
|
Liabilities incurred |
|
|
16 |
|
|
|
28 |
|
Liabilities settled |
|
|
(25 |
) |
|
|
(12 |
) |
Revision of estimated obligation |
|
|
140 |
|
|
|
311 |
|
Accretion expense on discounted obligation |
|
|
22 |
|
|
|
18 |
|
Foreign currency translation adjustment |
|
|
(26 |
) |
|
|
5 |
|
|
|
|
|
|
|
|
Asset retirement obligation as of end of period |
|
|
1,445 |
|
|
|
1,207 |
|
Less current portion |
|
|
68 |
|
|
|
55 |
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
1,377 |
|
|
$ |
1,152 |
|
|
|
|
|
|
|
|
During the first quarters of 2008 and 2007, Devon recognized increases of $140 million and
$311 million, respectively, to its ARO. The primary factors causing the 2008 fair value increase
were an overall increase in abandonment cost estimates and the effect of a decrease in the discount
rate used to present value the obligations. The primary factors causing the 2007 fair value
increase were an overall increase in abandonment cost estimates and an increase in the assumed
inflation rate.
3. Commodity Derivative Financial Instruments
Devon periodically enters into derivative financial instruments with respect to a portion of
its oil and gas production that hedge the future prices received. These instruments are used to
manage the inherent uncertainty of future revenues due to oil and gas price volatility. Devons
derivative financial instruments include financial price swaps, whereby Devon will receive a fixed
price for its production and pay a variable market price to the contract counterparty, and costless price
collars that set a floor and ceiling price for the hedged production. If the applicable monthly
price indices are outside of the ranges set by the floor and ceiling prices in the various collars,
Devon will settle the difference with the counterparty to the collars.
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
As discussed more fully in Note 1 to the consolidated financial statements in Devons 2007
Annual Report on Form 10-K, Devons derivative financial instruments are recognized at the current
fair value on the balance sheet. Unrealized changes in such fair values are recorded in the
statement of operations. Cash settlements with counterparties to Devons price swaps and price
collars are also recorded in the statement of operations.
The following tables present the fair values included in the accompanying balance sheet and
the cash settlements and unrealized losses included in the accompanying statement of operations
associated with Devons commodity derivative financial instruments.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Fair values: |
|
|
|
|
|
|
|
|
Other current assets gas price swaps |
|
$ |
|
|
|
$ |
12 |
|
Other long-term assets gas price collars |
|
$ |
7 |
|
|
$ |
|
|
Financial instruments, current liability: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
359 |
|
|
$ |
|
|
Gas price collars |
|
|
415 |
|
|
|
|
|
Oil price collars |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
Total financial instruments, current liability |
|
$ |
775 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
(8 |
) |
|
$ |
10 |
|
Gas price collars |
|
|
|
|
|
|
2 |
|
Oil price collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received |
|
|
(8 |
) |
|
|
12 |
|
|
|
|
|
|
|
|
Unrealized losses on fair value changes: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
(371 |
) |
|
|
(28 |
) |
Gas price collars |
|
|
(408 |
) |
|
|
(4 |
) |
Oil price collars |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total unrealized losses on fair value changes |
|
|
(780 |
) |
|
|
(32 |
) |
|
|
|
|
|
|
|
Net loss on oil and gas derivative financial instruments |
|
$ |
(788 |
) |
|
$ |
(20 |
) |
|
|
|
|
|
|
|
4. Debt
Credit Facilities
In April 2008, Devon extended the maturity of $2.0 billion of its existing $2.5 billion
five-year, syndicated, unsecured revolving line of credit (the Senior Credit Facility) from April
7, 2012 to April 7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not
approve a maturity date extension. Therefore, the maturity date for $0.5 billion of the Senior
Credit Facility remains at April 7, 2012.
The Senior Credit Facility and Devons $1.5 billion 364-day, syndicated, unsecured revolving
senior credit facility 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, 2008, Devon was in compliance with this covenant. Devons debt-to-capitalization ratio at
March 31, 2008, as calculated pursuant to the terms of the agreement, was 23.3%.
As of March 31, 2008, Devons combined available capacity under its credit facilities was
approximately $1.5 billion. This available capacity is net of $920 million of outstanding
borrowings, $1.4 billion of outstanding commercial paper and $143 million of
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
outstanding letters of credit.
As of March 31, 2008 interest rates on Devons borrowings under its credit facilities and
commercial paper program averaged 3.2% and 3.3%, respectively.
Exchangeable Debentures
During the first quarter of 2008, certain holders of exchangeable debentures exercised their
option to exchange their debentures for shares of Chevron Corporation (Chevron) common stock that
Devon owns prior to the debentures August 15, 2008 maturity date. In lieu of delivering Chevron
common stock to an exchanging debenture holder, Devon may, at its option, pay to such holder an
amount of cash equal to the market value of Chevron common stock. Devon elected to pay the
exchanging debenture holders cash totaling $41 million in lieu of delivering shares of Chevron
common stock. As a result of these exchanges, Devon retired outstanding exchangeable debentures
with a book value totaling $25 million and reduced the related embedded derivative options balance
by $16 million.
As of March 31, 2008, the Chevron exchangeable debentures are due within one year. However,
Devon continues to classify this debt as long-term because it has the intent and ability to
refinance these debentures on a long-term basis with the available capacity under its existing
credit facilities or other long-term financing arrangements.
5. Fair Value Measurements
Certain of Devons assets and liabilities are reported at fair value in the accompanying
balance sheets. Such assets and liabilities include amounts for both financial and nonfinancial
instruments. The following tables provide fair value measurement information for such assets and
liabilities as of March 31, 2008 and December 31, 2007. Following the tables, additional
information is provided for those assets and liabilities in which Devon uses significant
unobservable inputs (Level 3) to measure fair value.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of March 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): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term and long-term investments |
|
$ |
152 |
|
|
$ |
152 |
|
|
$ |
23 |
|
|
$ |
|
|
|
$ |
129 |
|
Investment in Chevron common stock |
|
$ |
1,211 |
|
|
$ |
1,211 |
|
|
$ |
1,211 |
|
|
$ |
|
|
|
$ |
|
|
Net oil and gas price swaps and collars |
|
$ |
(768 |
) |
|
$ |
(768 |
) |
|
$ |
|
|
|
$ |
(768 |
) |
|
$ |
|
|
Embedded option in exchangeable debentures |
|
$ |
(376 |
) |
|
$ |
(376 |
) |
|
$ |
|
|
|
$ |
(376 |
) |
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,445 |
) |
|
$ |
(1,445 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,445 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007 |
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
|
|
|
Quoted |
|
Significant |
|
|
|
|
|
|
|
|
|
|
|
|
Prices in |
|
Other |
|
Significant |
|
|
|
|
|
|
|
|
|
|
Active |
|
Observable |
|
Unobservable |
|
|
Carrying |
|
Total Fair |
|
Markets |
|
Inputs |
|
Inputs |
|
|
Amount |
|
Value |
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
Financial Assets (Liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
372 |
|
|
$ |
372 |
|
|
$ |
372 |
|
|
$ |
|
|
|
$ |
|
|
Investment in Chevron common stock |
|
$ |
1,324 |
|
|
$ |
1,324 |
|
|
$ |
1,324 |
|
|
$ |
|
|
|
$ |
|
|
Oil and gas price swaps and collars |
|
$ |
12 |
|
|
$ |
12 |
|
|
$ |
|
|
|
$ |
12 |
|
|
$ |
|
|
Embedded option in exchangeable debentures |
|
$ |
(488 |
) |
|
$ |
(488 |
) |
|
$ |
|
|
|
$ |
(488 |
) |
|
$ |
|
|
Asset retirement obligation |
|
$ |
(1,318 |
) |
|
$ |
(1,318 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1,318 |
) |
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Level 3 Fair Value Measurements
Short-term and long-term investments Devons short-term and long-term investments presented
in the tables above as of March 31, 2008 and December 31, 2007 consisted entirely of auction rate
securities, which are discussed in greater detail in Note 1. As of March 31, 2008 and December 31,
2007, Devon estimated the fair values of its short-term investments using quoted market prices.
However, due to the auction failures discussed in Note 1 and the lack of an active market for
Devons long-term auction rate securities, quoted market prices for these securities were not
available as of March 31, 2008. Therefore, Devon used valuation techniques that rely on
unobservable, or Level 3, inputs to estimate the fair values of its long-term auction rate
securities as of March 31, 2008. These inputs were based on the AAA credit rating of the
securities, the probability of full repayment of the securities considering the United States
government guarantees of the underlying student loans and the collection of all accrued interest to
date. As a result of using these inputs, Devon concluded the estimated fair values of its long-term
auction rate securities approximated the par values as of March 31, 2008. At this time, Devon does
not believe the values of its long-term securities are impaired. Included below is a summary of the
changes in Devons Level 3 short-term and long-term investments during the first quarter of 2008
(in millions).
|
|
|
|
|
Beginning balance |
|
$ |
|
|
Transfers from Level 1 to Level 3 |
|
|
129 |
|
|
|
|
|
Ending balance |
|
$ |
129 |
|
|
|
|
|
Asset retirement obligation The fair values of the asset retirement obligations are
estimated using internal discounted cash flow calculations based upon Devons estimates of future
retirement costs. A summary of the changes in Devons asset retirement obligation, including a
revision of the estimated fair value in 2008 and 2007, is presented in Note 2.
6. Retirement Plans
Net Periodic Benefit Cost and Other Comprehensive Income
The following table presents the components of net periodic benefit cost and other
comprehensive income for Devons pension and other post retirement benefit plans for the
three-month periods ended March 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
2008 |
|
|
2007 |
|
|
|
(In
millions) |
|
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
10 |
|
|
$ |
8 |
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
14 |
|
|
|
11 |
|
|
|
2 |
|
|
|
1 |
|
Expected return on plan assets |
|
|
(13 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
Net actuarial loss |
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
|
15 |
|
|
|
11 |
|
|
|
2 |
|
|
|
1 |
|
Other comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition of net actuarial
loss in net
periodic benefit cost |
|
|
(5 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized |
|
$ |
10 |
|
|
$ |
7 |
|
|
$ |
2 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Dividends
Devon paid common stock dividends of $71 million (or $0.16 per share) and $62 million (or
$0.14 per share) in the first quarter of 2008 and first quarter of 2007, respectively. Devon also
paid $2 million in the first quarters of 2008 and 2007 to preferred stockholders.
8. Commitments and Contingencies
Devon is party to various legal actions arising in the normal course of business. Matters that
are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued.
Such accruals are based on information known about the matters, Devons estimates of the outcomes
of such matters and its experience in contesting, litigating and settling similar matters. None of
the actions are believed by management to involve future amounts that would be material to Devons
financial position or results of operations after consideration of recorded accruals although
actual amounts could differ materially from managements estimate.
Royalty Matters
Numerous gas producers and related parties, including Devon, have been named in various
lawsuits alleging violation of the federal False Claims Act. The suits allege that the producers
and related parties used below-market prices, improper deductions, improper measurement techniques
and transactions with affiliates, which resulted in underpayment of royalties in connection with
natural gas and NGLs produced and sold from federal and Indian owned or controlled lands. The
principal suit in which Devon is a defendant is United States ex rel. Wright v. Chevron USA, Inc.
et al. (the Wright case). The suit was originally filed in August 1996 in the United States
District Court for the Eastern District of Texas, but was consolidated in October 2000 with other
suits for pre-trial proceedings in the United States District Court for the District of Wyoming. On
July 10, 2003, the District of Wyoming remanded the Wright case back to the Eastern District of
Texas to resume proceedings. On April 12, 2007, the court entered a trial plan and scheduling order
in which the case will proceed in phases. Two phases have been scheduled to date, with the first
scheduled to begin in August 2008 and the second scheduled to begin in February 2009. Devon is not
included in the groups of defendants selected for these first two phases. Devon believes that it
has acted reasonably, has legitimate and strong defenses to all allegations in the suit, and has
paid royalties in good faith. Devon does not currently believe that it is subject to material
exposure in association with this lawsuit and no liability has been recorded in connection
therewith.
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of
this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief
from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain
years by the Minerals Management Service (the MMS) have contained price thresholds, such that if
the market prices for oil or natural gas exceeded the thresholds for a given year, royalty relief
would not be granted for that year. Deep water leases issued in 1998 and 1999 did not include price
thresholds. In 2006, the MMS informed Devon and other oil and gas companies that the omission of
price thresholds from these leases was an error on its part and was not its intention. Accordingly,
the MMS invited Devon and the other affected oil and gas producers to renegotiate the terms and
conditions of the 1998 and 1999 leases to add price threshold provisions to the lease agreements
for periods after October 1, 2006. Devon has not renegotiated any of its existing leases.
The U.S. House of Representatives in January 2007 passed legislation that would have required
companies to renegotiate the 1998 and 1999 leases as a condition of securing future federal leases.
This legislation was not passed by the U.S. Senate. However, Congress may consider similar
legislation in the future. Although Devon has not signed renegotiated leases, it has accrued
through March 31, 2008, approximately $34 million for royalties that would be due if price
thresholds were added to its 1998 and 1999 leases effective October 1, 2006.
Additionally, Devon has $29 million accrued at March 31, 2008 for royalties related to leases
issued under the Deep Water Royalty Relief Act in years other than 1998 or 1999. The leases issued
in these other years did include price thresholds, but in
October 2007 a federal district court ruled in favor of a plaintiff who had challenged the
legality of including price thresholds in these leases. This judgment is subject to appeal, and
Devon will continue to accrue for royalties on these leases until the matter is resolved.
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
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,
2008, Devons balance sheet included $3 million of noncurrent accrued liabilities, reflected in
other liabilities, related to these and other environmental remediation liabilities. Devon does not
currently believe there is a reasonable possibility of incurring additional material costs in
excess of the current accruals recognized for such environmental remediation activities. With
respect to the sites in which Devon subsidiaries are PRPs, Devons conclusion is based in large
part on (i) Devons participation in consent decrees with both other PRPs and the Environmental
Protection Agency, which provide for performing the scope of work required for remediation and
contain covenants not to sue as protection to the PRPs, (ii) participation in groups as a de
minimis PRP, and (iii) the availability of other defenses to liability. As a result, Devons
monetary exposure is not expected to be material.
Hurricane Contingencies
Historically, Devon maintained a comprehensive insurance program that included coverage for
physical damage to its offshore facilities caused by hurricanes. Devons historical insurance
program also included substantial business interruption coverage, which Devon is utilizing to
recover costs associated with the suspended production related to hurricanes that struck the Gulf
of Mexico in the third quarter of 2005. Under the terms of this insurance program, Devon was
entitled to be reimbursed for the portion of production suspended longer than forty-five days,
subject to upper limits to oil and natural gas prices. Also, the terms of the insurance include a
standard, per-event deductible of $1 million for offshore losses as well as a $15 million aggregate
annual deductible.
Based on current estimates of physical damage and the anticipated length of time Devon will
have had production suspended, Devon expects its policy recoveries will exceed repair costs and
deductible amounts. This expectation is based upon several variables, including the $467 million
received in 2006 as a full settlement of the amount due from Devons primary insurers and $13
million received in 2007 as a full settlement of the amount due from certain of Devons secondary
insurers. As of March 31, 2008, $364 million of these proceeds had been utilized as reimbursement
of past repair costs and deductible amounts. The remaining proceeds of $116 million will be
utilized as reimbursement of Devons anticipated future repair costs. Devon continues to negotiate
with its other secondary insurers and expects to receive additional policy recoveries as a result
of such negotiations.
Should Devons total policy recoveries, including the partial settlements already received
from Devons primary and secondary insurers, exceed all repair costs and deductible amounts, such
excess will be recognized as other income in the statement of operations in the period in which
such determination can be made.
The policy underlying the insurance program terms described above expired on August 31, 2006.
Devons current insurance program includes business interruption and physical damage coverage for
its business. However, due to significant changes in the insurance marketplace, Devon has only been
able to obtain a de minimis amount of coverage for any damage that may be caused by named
windstorms in the Gulf of Mexico. Devon has not experienced any windstorm-related losses under this
new insurance arrangement through March 31, 2008.
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business.
However, to Devons knowledge as of the date of this report, there were no other material pending
legal proceedings to which Devon is a party or to which any of its property is subject.
9. Change in Fair Value of Non-Oil and Gas Financial Instruments
The components of the change in fair value of non-oil and gas financial instruments include
the following:
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
Losses (gains) from: |
|
|
|
|
|
|
|
|
Chevron common stock |
|
$ |
113 |
|
|
$ |
(6 |
) |
Option embedded in exchangeable debentures |
|
|
(97 |
) |
|
|
8 |
|
Interest rate swaps |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
16 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
10. Discontinued Operations
Divestiture Activity
In November 2006 and January 2007, Devon announced its plans to divest its operations in Egypt
and West Africa, including Equatorial Guinea, Gabon, Cote DIvoire and other countries in the
region. Pursuant to accounting rules for discontinued operations, Devon has classified all amounts
related to its operations in Egypt and West Africa as discontinued operations.
In the fourth quarter of 2007, Devon completed the sale of its Egyptian operations and
recognized a $90 million after-tax gain from proceeds of $341 million.
Devon has entered into agreements to sell its operations in Equatorial Guinea, Gabon, Cote
DIvoire and other smaller countries for $2.6 billion. Devon is obtaining the necessary partner and
government approvals for these properties. Devon expects to complete the majority of these sales,
including Equatorial Guinea, during the second quarter of 2008. Had these transactions closed on
March 31, 2008, Devon would have recognized after-tax gains of approximately $850 million. The
gains ultimately recorded when the transactions close will depend on the carrying values of Devons
assets and liabilities at the closing dates, as well as the effect of any purchase price
adjustments between the effective dates and the actual closing dates of the sales.
Financial Statement Information
Revenues related to Devons discontinued operations totaled $205 million and $175 million for
the three months ended March 31, 2008 and 2007, respectively.
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, 2008 and December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Assets: |
|
|
|
|
|
|
|
|
Cash |
|
$ |
8 |
|
|
$ |
9 |
|
Accounts receivable |
|
|
79 |
|
|
|
83 |
|
Other current assets |
|
|
25 |
|
|
|
28 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
112 |
|
|
$ |
120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term assets property and equipment, net of
accumulated depreciation, depletion and amortization |
|
$ |
1,531 |
|
|
$ |
1,512 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
Accounts payable trade |
|
$ |
19 |
|
|
$ |
23 |
|
Revenues and royalties due to others |
|
|
5 |
|
|
|
11 |
|
Current portion of asset retirement obligation |
|
|
9 |
|
|
|
9 |
|
Accrued expenses and other current liabilities |
|
|
140 |
|
|
|
102 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
173 |
|
|
$ |
145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
35 |
|
|
$ |
35 |
|
Deferred income taxes |
|
|
390 |
|
|
|
366 |
|
Other long-term liabilities |
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
428 |
|
|
$ |
404 |
|
|
|
|
|
|
|
|
11. Earnings Per Share
The following table reconciles earnings from continuing operations and common shares
outstanding used in the calculations of basic and diluted earnings per share for the three-month
periods ended March 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
|
|
|
|
|
|
|
|
Earnings |
|
|
Weighted |
|
|
|
|
|
|
Applicable to |
|
|
Average |
|
|
Net |
|
|
|
Common |
|
|
Common Shares |
|
|
Earnings |
|
|
|
Stockholders |
|
|
Outstanding |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended 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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
574 |
|
|
|
|
|
|
|
|
|
Less preferred stock dividends |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
572 |
|
|
|
444 |
|
|
$ |
1.29 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
572 |
|
|
|
450 |
|
|
$ |
1.27 |
|
|
|
|
|
|
|
|
|
|
|
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. During the three-month periods ended March 31,
2008 and 2007, 1.8 million shares and 4.2 million shares, respectively, were excluded from the
diluted earnings per share calculations.
12. 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, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
1,992 |
|
|
$ |
1,030 |
|
|
$ |
1,635 |
|
|
$ |
4,657 |
|
Property and equipment, net of accumulated
depreciation, depletion and amortization |
|
|
18,868 |
|
|
|
8,831 |
|
|
|
1,234 |
|
|
|
28,933 |
|
Goodwill |
|
|
3,050 |
|
|
|
2,936 |
|
|
|
68 |
|
|
|
6,054 |
|
Other long-term assets |
|
|
1,544 |
|
|
|
68 |
|
|
|
1,729 |
|
|
|
3,341 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
25,454 |
|
|
$ |
12,865 |
|
|
$ |
4,666 |
|
|
$ |
42,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
3,933 |
|
|
$ |
573 |
|
|
$ |
489 |
|
|
$ |
4,995 |
|
Long-term debt |
|
|
3,395 |
|
|
|
2,976 |
|
|
|
|
|
|
|
6,371 |
|
Asset retirement obligation, long-term |
|
|
675 |
|
|
|
631 |
|
|
|
71 |
|
|
|
1,377 |
|
Other long-term liabilities |
|
|
1,028 |
|
|
|
44 |
|
|
|
433 |
|
|
|
1,505 |
|
Deferred income taxes |
|
|
4,284 |
|
|
|
1,963 |
|
|
|
92 |
|
|
|
6,339 |
|
Stockholders equity |
|
|
12,139 |
|
|
|
6,678 |
|
|
|
3,581 |
|
|
|
22,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
25,454 |
|
|
$ |
12,865 |
|
|
$ |
4,666 |
|
|
$ |
42,985 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
443 |
|
|
$ |
340 |
|
|
$ |
467 |
|
|
$ |
1,250 |
|
Gas sales |
|
|
1,236 |
|
|
|
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 non-oil and gas derivative 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 tax
expense |
|
|
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 tax expense |
|
|
|
|
|
|
|
|
|
|
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, before revision of future ARO |
|
$ |
1,311 |
|
|
$ |
516 |
|
|
$ |
151 |
|
|
$ |
1,978 |
|
Revision of future ARO |
|
|
70 |
|
|
|
73 |
|
|
|
(3 |
) |
|
|
140 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,381 |
|
|
$ |
589 |
|
|
$ |
148 |
|
|
$ |
2,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
234 |
|
|
$ |
153 |
|
|
$ |
304 |
|
|
$ |
691 |
|
Gas sales |
|
|
889 |
|
|
|
356 |
|
|
|
1 |
|
|
|
1,246 |
|
NGL sales |
|
|
136 |
|
|
|
41 |
|
|
|
|
|
|
|
177 |
|
Net loss on oil and gas derivative financial instruments |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
(20 |
) |
Marketing and midstream revenues |
|
|
371 |
|
|
|
8 |
|
|
|
|
|
|
|
379 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,610 |
|
|
|
558 |
|
|
|
305 |
|
|
|
2,473 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses and other income, net: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
248 |
|
|
|
143 |
|
|
|
39 |
|
|
|
430 |
|
Production taxes |
|
|
56 |
|
|
|
1 |
|
|
|
23 |
|
|
|
80 |
|
Marketing and midstream operating costs and
expenses |
|
|
266 |
|
|
|
4 |
|
|
|
|
|
|
|
270 |
|
Depreciation, depletion and amortization of oil and
gas properties |
|
|
371 |
|
|
|
160 |
|
|
|
56 |
|
|
|
587 |
|
Depreciation and amortization of non-oil and gas
properties |
|
|
41 |
|
|
|
5 |
|
|
|
|
|
|
|
46 |
|
Accretion of asset retirement obligation |
|
|
10 |
|
|
|
7 |
|
|
|
1 |
|
|
|
18 |
|
General and administrative expenses |
|
|
92 |
|
|
|
25 |
|
|
|
2 |
|
|
|
119 |
|
Interest expense |
|
|
59 |
|
|
|
51 |
|
|
|
|
|
|
|
110 |
|
Change in fair value of non-oil and gas derivative financial
instruments |
|
|
2 |
|
|
|
(1 |
) |
|
|
|
|
|
|
1 |
|
Other income, net |
|
|
(12 |
) |
|
|
(3 |
) |
|
|
(11 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses and other income, net |
|
|
1,133 |
|
|
|
392 |
|
|
|
110 |
|
|
|
1,635 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income tax
expense |
|
|
477 |
|
|
|
166 |
|
|
|
195 |
|
|
|
838 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
67 |
|
|
|
62 |
|
|
|
60 |
|
|
|
189 |
|
Deferred |
|
|
86 |
|
|
|
(1 |
) |
|
|
(10 |
) |
|
|
75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
153 |
|
|
|
61 |
|
|
|
50 |
|
|
|
264 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
|
324 |
|
|
|
105 |
|
|
|
145 |
|
|
|
574 |
|
Discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations before income tax expense |
|
|
|
|
|
|
|
|
|
|
137 |
|
|
|
137 |
|
Income tax expense |
|
|
|
|
|
|
|
|
|
|
60 |
|
|
|
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
|
|
|
|
|
|
|
|
|
77 |
|
|
|
77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
324 |
|
|
|
105 |
|
|
|
222 |
|
|
|
651 |
|
Preferred stock dividends |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings applicable to common stockholders |
|
$ |
322 |
|
|
$ |
105 |
|
|
$ |
222 |
|
|
$ |
649 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future ARO |
|
$ |
943 |
|
|
$ |
469 |
|
|
$ |
111 |
|
|
$ |
1,523 |
|
Revision of future ARO |
|
|
210 |
|
|
|
99 |
|
|
|
2 |
|
|
|
311 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,153 |
|
|
$ |
568 |
|
|
$ |
113 |
|
|
$ |
1,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
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, 2008, compared to the three-month
period ended March 31, 2007, and in our financial condition and liquidity since December 31, 2007.
It is presumed that readers have read or have access to our 2007 Annual Report on Form 10-K, which
includes disclosures regarding critical accounting policies and estimates as part of Managements
Discussion and Analysis of Financial Condition and Results of Operations. Unless otherwise stated,
all dollar amounts are expressed in U.S. dollars.
Overview
During the first quarter of 2008, we generated net earnings of $749 million, or $1.66 per
diluted share, representing a 15% increase over the first quarter of 2007. Additionally, net cash
provided by operating activities climbed to a record quarterly amount of $2.3 billion, representing
a 49% increase over 2007. These increases in earnings and cash flow are largely attributable to the
following factors:
|
|
|
Production increased 10% to 58 million Boe. |
|
|
|
|
Our combined realized price without hedges for oil, gas and NGLs increased 38% to $55.07
per Boe. |
|
|
|
|
Our oil and gas hedges generated a net loss of $788 million in the first quarter of
2008, of which $780 million represented an unrealized fair value loss and $8 million
represented cash payments to counterparties. |
|
|
|
|
Marketing and midstream operating profit increased 59% to $173 million. |
|
|
|
|
Per unit operating costs rose 14% to $10.99. |
|
|
|
|
Cash spent on capital expenditures for oil and gas exploration and development
activities were $1.7 billion. |
Additionally, we have continued to make progress toward the divestitures of our West African
operations. We have entered into agreements to sell our operations in Equatorial Guinea, Gabon,
Cote DIvoire and other smaller countries for $2.6 billion. We are obtaining the necessary partner
and government approvals for these properties. We expect to complete the majority of these sales,
including Equatorial Guinea, during the second quarter of 2008.
Results of Operations
Revenues
Oil, Gas and NGL Sales
The three-month comparison of our oil, gas and NGL production and the related prices realized
without the effect of hedges is shown in the following tables. The amounts for all periods
presented exclude our Egyptian operations that were sold in the fourth quarter of 2007 and our West
African operations, which are classified as discontinued operations in our financial statements.
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
14 |
|
|
|
13 |
|
|
|
+7 |
% |
Gas (Bcf) |
|
|
223 |
|
|
|
202 |
|
|
|
+10 |
% |
NGLs (MMBbls) |
|
|
7 |
|
|
|
6 |
|
|
|
+15 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
58 |
|
|
|
53 |
|
|
|
+10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
88.23 |
|
|
$ |
52.11 |
|
|
|
+69 |
% |
Gas (Per Mcf) |
|
$ |
7.31 |
|
|
$ |
6.17 |
|
|
|
+18 |
% |
NGLs (Per Bbl) |
|
$ |
47.40 |
|
|
$ |
29.33 |
|
|
|
+62 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
55.07 |
|
|
$ |
39.94 |
|
|
|
+38 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
1,250 |
|
|
$ |
691 |
|
|
|
+81 |
% |
Gas sales |
|
|
1,630 |
|
|
|
1,246 |
|
|
|
+31 |
% |
NGL sales |
|
|
328 |
|
|
|
177 |
|
|
|
+86 |
% |
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
3,208 |
|
|
$ |
2,114 |
|
|
|
+52 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Domestic |
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
4 |
|
|
|
4 |
|
|
|
+3 |
% |
Gas (Bcf) |
|
|
171 |
|
|
|
146 |
|
|
|
+17 |
% |
NGLs (MMBbls) |
|
|
6 |
|
|
|
5 |
|
|
|
+21 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
39 |
|
|
|
34 |
|
|
|
+16 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
95.70 |
|
|
$ |
52.22 |
|
|
|
+83 |
% |
Gas (Per Mcf) |
|
$ |
7.24 |
|
|
$ |
6.08 |
|
|
|
+19 |
% |
NGLs (Per Bbl) |
|
$ |
44.86 |
|
|
$ |
27.59 |
|
|
|
+63 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
49.84 |
|
|
$ |
37.29 |
|
|
|
+34 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
443 |
|
|
$ |
234 |
|
|
|
+89 |
% |
Gas sales |
|
|
1,236 |
|
|
|
889 |
|
|
|
+39 |
% |
NGL sales |
|
|
266 |
|
|
|
136 |
|
|
|
+96 |
% |
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
1,945 |
|
|
$ |
1,259 |
|
|
|
+55 |
% |
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada |
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
5 |
|
|
|
4 |
|
|
|
+33 |
% |
Gas (Bcf) |
|
|
52 |
|
|
|
56 |
|
|
|
-7 |
% |
NGLs (MMBbls) |
|
|
1 |
|
|
|
1 |
|
|
|
-11 |
% |
Oil, Gas and NGLs (MMBoe)(1) |
|
|
14 |
|
|
|
14 |
|
|
|
+3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
72.68 |
|
|
$ |
43.51 |
|
|
|
+67 |
% |
Gas (Per Mcf) |
|
$ |
7.53 |
|
|
$ |
6.43 |
|
|
|
+17 |
% |
NGLs (Per Bbl) |
|
$ |
62.67 |
|
|
$ |
37.03 |
|
|
|
+69 |
% |
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
55.42 |
|
|
$ |
39.71 |
|
|
|
+40 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
340 |
|
|
$ |
153 |
|
|
|
+123 |
% |
Gas sales |
|
|
389 |
|
|
|
356 |
|
|
|
+9 |
% |
NGL sales |
|
|
62 |
|
|
|
41 |
|
|
|
+51 |
% |
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
791 |
|
|
$ |
550 |
|
|
|
+44 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(2) |
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MMBbls) |
|
|
5 |
|
|
|
5 |
|
|
|
-8 |
% |
Gas (Bcf) |
|
|
|
|
|
|
|
|
|
|
+105 |
% |
NGLs (MMBbls) |
|
|
|
|
|
|
|
|
|
|
N/M |
|
Oil, Gas and NGLs (MMBoe)(1) |
|
|
5 |
|
|
|
5 |
|
|
|
-7 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized prices without hedges |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Per Bbl) |
|
$ |
96.08 |
|
|
$ |
57.72 |
|
|
|
+66 |
% |
Gas (Per Mcf) |
|
$ |
8.41 |
|
|
$ |
3.21 |
|
|
|
+162 |
% |
NGLs (Per Bbl) |
|
$ |
|
|
|
$ |
|
|
|
|
N/M |
|
Oil, Gas and NGLs (Per Boe)(1) |
|
$ |
95.24 |
|
|
$ |
57.40 |
|
|
|
+66 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues ($ in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales |
|
$ |
467 |
|
|
$ |
304 |
|
|
|
+53 |
% |
Gas sales |
|
|
5 |
|
|
|
1 |
|
|
|
+437 |
% |
NGL sales |
|
|
|
|
|
|
|
|
|
|
N/M |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Gas and NGL sales |
|
$ |
472 |
|
|
$ |
305 |
|
|
|
+54 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Gas volumes are converted to Boe or MMBoe at the rate of six Mcf of gas per barrel
of oil, based upon the approximate relative energy content of natural gas and oil, which rate
is not necessarily indicative of the relationship of oil and gas prices. NGL volumes are
converted to Boe on a one-to-one basis with oil. |
|
(2) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
|
N/M |
|
Not meaningful. |
25
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, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2007 sales |
|
$ |
691 |
|
|
$ |
1,246 |
|
|
$ |
177 |
|
|
$ |
2,114 |
|
Changes due to volumes |
|
|
47 |
|
|
|
131 |
|
|
|
26 |
|
|
|
204 |
|
Changes due to prices |
|
|
512 |
|
|
|
253 |
|
|
|
125 |
|
|
|
890 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 sales |
|
$ |
1,250 |
|
|
$ |
1,630 |
|
|
$ |
328 |
|
|
$ |
3,208 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales increased $47 million due to a one million barrel, or 7%, increase in production.
The increase in production was primarily due to increased development activity in our Lloydminster
area in Canada.
Oil sales increased $512 million as a result of a 69% increase in our realized price without
hedges. The average NYMEX West Texas Intermediate index price increased 67% during the same time
period, accounting for the majority of the increase.
Gas Sales
A 21 Bcf, or 10%, increase in production caused gas sales to increase by $131 million. Our
drilling and development program in the Barnett Shale field in north Texas contributed 20 Bcf to
the gas production increase. This increase and the effect of new drilling and development in our
other North American properties were partially offset by natural production declines.
Gas sales increased $253 million as a result of an 18% increase in our realized price without
hedges. This increase is largely due to increases in the regional index prices upon which our gas
sales are based.
Net Loss on Oil and Gas Derivative Financial Instruments
The following tables provide financial information associated with our oil and gas hedges for
the first quarter of 2008 and 2007. The first table presents the cash settlements and unrealized
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 quarter of 2008 and
2007. The prices do not include the effects of the unrealized losses for the first quarter of 2008
and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
$ |
(8 |
) |
|
$ |
10 |
|
Gas price collars |
|
|
|
|
|
|
2 |
|
Oil price collars |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements (paid) received |
|
|
(8 |
) |
|
|
12 |
|
|
|
|
|
|
|
|
Unrealized losses on fair value changes: |
|
|
|
|
|
|
|
|
Gas price swaps |
|
|
(371 |
) |
|
|
(28 |
) |
Gas price collars |
|
|
(408 |
) |
|
|
(4 |
) |
Oil price collars |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total unrealized losses on fair value changes |
|
|
(780 |
) |
|
|
(32 |
) |
|
|
|
|
|
|
|
Net loss on oil and gas derivative financial instruments |
|
$ |
(788 |
) |
|
$ |
(20 |
) |
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2007 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
52.11 |
|
|
$ |
6.17 |
|
|
$ |
29.33 |
|
|
$ |
39.94 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.06 |
|
|
|
|
|
|
|
0.22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
52.11 |
|
|
$ |
6.23 |
|
|
$ |
29.33 |
|
|
$ |
40.16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our oil and gas derivative financial instruments include price swaps and costless collars. For
the price swaps, we receive a fixed price for our production and pay a variable market price to the
contract counterparty. The costless price collars set a floor and ceiling price for the hedged
production. If the applicable monthly price indices are outside of the ranges set by the floor and
ceiling prices in the various collars, we 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 2008, we paid $8 million, or $0.04 per Mcf, to counterparties to
settle our gas price swaps. During the first quarter of 2007, we received $12 million, or $0.06 per
Mcf, from counterparties to settle our gas price swaps and collars.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes
in the fair values of our oil and gas derivative instruments in each reporting period. We estimate
the fair values of our oil and gas derivative financial instruments primarily by using internal
discounted cash flow calculations. From time to time, we validate our valuation techniques by
comparing our internally generated fair value estimates with those obtained from contract
counterparties and/or brokers.
The most significant variable to our cash flow calculations is our estimate of future
commodity prices. We base our estimate of future prices upon published forward commodity price
curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas
Intermediate forward curve for oil instruments. Based on the amount of volumes subject to price
swaps and collars at March 31, 2008, a 10% increase in these forward curves would have increased
our first quarter 2008 unrealized loss for our oil and gas derivative financial instruments by
approximately $500 million. Another key input to our cash flow calculations is our estimate of
volatility for these forward curves, which we base primarily upon implied volatility.
During the first quarter of 2008, we recognized unrealized losses totaling $779 million
related to our gas derivative instruments. This loss results primarily from a significant increase
in the Inside FERC Henry Hub forward curve subsequent to the trade dates for our gas price swaps
and collars.
During the first quarter of 2007, we recognized unrealized losses totaling $32 million related
to our gas derivative instruments.
27
Marketing and Midstream Revenues and Operating Costs and Expenses
The details of the changes in marketing and midstream revenues, operating costs and expenses
and the resulting operating profit between the three months ended March 31, 2008 and 2007 are shown
in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Marketing and midstream ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
555 |
|
|
$ |
379 |
|
|
|
+46 |
% |
Operating costs and expenses |
|
|
382 |
|
|
|
270 |
|
|
|
+41 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
173 |
|
|
$ |
109 |
|
|
|
+59 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures and are
not calculated using the rounded figures included in this table. |
Marketing and midstream revenues increased $176 million and operating costs and expenses also
increased $112 million, causing operating profit to increase $64 million. Revenues and expenses
increased primarily due to higher natural gas and NGL prices, as well as higher gas pipeline
throughput in the Barnett Shale.
Oil, Gas and NGL Production and Operating Expenses
The three-month comparison of oil, gas and NGL production and operating expenses are shown in
the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
Production and operating expenses ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
506 |
|
|
$ |
430 |
|
|
|
+18 |
% |
Production taxes |
|
|
134 |
|
|
|
80 |
|
|
|
+66 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses |
|
$ |
640 |
|
|
$ |
510 |
|
|
|
+25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
$ |
8.69 |
|
|
$ |
8.13 |
|
|
|
+7 |
% |
Production taxes |
|
|
2.30 |
|
|
|
1.52 |
|
|
|
+51 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total production and operating expenses per Boe |
|
$ |
10.99 |
|
|
$ |
9.65 |
|
|
|
+14 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 $76 million in the first quarter of 2008. The largest contributor to this
increase was our 10% growth in production, which caused an increase of $43 million. Furthermore,
changes in the exchange rate between the U.S. and Canadian dollar also caused LOE to increase $28
million. This exchange rate effect was also the primary factor causing LOE per Boe to increase.
28
Production Taxes
The following table details the changes in production taxes between the three months ended
March 31, 2008 and 2007. The majority of our production taxes are assessed on our U.S. onshore
properties and are based on a fixed percentage of revenues. Therefore, the changes due to revenues
in the following table primarily relate to changes in oil, gas and NGL revenues from our U.S.
onshore properties.
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
(In millions) |
|
2007 production taxes |
|
$ |
80 |
|
Change due to revenues |
|
|
42 |
|
Change due to rate |
|
|
12 |
|
|
|
|
|
2008 production taxes |
|
$ |
134 |
|
|
|
|
|
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, 2008 and 2007 are shown in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change(1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total production volumes (MMBoe) |
|
|
58 |
|
|
|
53 |
|
|
|
+10 |
% |
DD&A rate ($ per Boe) |
|
$ |
12.64 |
|
|
$ |
11.09 |
|
|
|
+14 |
% |
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
737 |
|
|
$ |
587 |
|
|
|
+25 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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, 2008 and 2007.
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
(In millions) |
|
2007 DD&A |
|
$ |
587 |
|
Change due to volumes |
|
|
59 |
|
Change due to rate |
|
|
91 |
|
|
|
|
|
2008 DD&A |
|
$ |
737 |
|
|
|
|
|
The 10% production increase caused oil and gas property related DD&A to increase $59 million.
In addition, oil and gas property related DD&A increased $91 million due to a 14% increase in the
DD&A rate. The largest contributor to the rate increase was inflationary pressure on both costs
incurred during 2007 and 2008 as well as the estimated development costs to be spent in future
periods on proved undeveloped reserves. Other factors contributing to the rate increase include the
transfer of previously unproved costs to the depletable base as a result of 2007 and 2008 drilling
activities and a higher Canadian-to-U.S. dollar exchange rate in 2008.
29
General and Administrative Expenses (G&A)
The following schedule includes the components of G&A expense for the three months ended March
31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
Change (1) |
|
|
|
(In millions) |
|
|
|
|
|
Gross G&A |
|
$ |
277 |
|
|
$ |
212 |
|
|
|
+31 |
% |
Capitalized G&A |
|
|
(99 |
) |
|
|
(64 |
) |
|
|
+55 |
% |
Reimbursed G&A |
|
|
(30 |
) |
|
|
(29 |
) |
|
|
+4 |
% |
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
148 |
|
|
$ |
119 |
|
|
|
+24 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
Gross G&A increased $65 million in the first quarter of 2008 compared to the same period of
2007. Higher employee compensation and benefits costs related to our workforce growth and industry
inflation caused gross G&A to increase $55 million. The $35 million increase in capitalized G&A
during the first quarter of 2008 is also primarily due to higher employee compensation and benefits
costs.
Interest Expense
The following schedule includes the components of interest expense for the three months ended
March 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended Mach 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
126 |
|
|
$ |
128 |
|
Capitalized interest |
|
|
(31 |
) |
|
|
(23 |
) |
Other |
|
|
7 |
|
|
|
5 |
|
|
|
|
|
|
|
|
Total |
|
$ |
102 |
|
|
$ |
110 |
|
|
|
|
|
|
|
|
Capitalized interest increased primarily due to an increase in development activities and
related accumulated costs for projects in the Gulf of Mexico and Brazil.
Change in Fair Value of Non-Oil and Gas Financial Instruments
The following schedule includes the components of the change in fair value of non-oil and gas
financial instruments for the three months ended March 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Losses (gains) from: |
|
|
|
|
|
|
|
|
Investment in Chevron common stock |
|
$ |
113 |
|
|
$ |
(6 |
) |
Option embedded in exchangeable debentures |
|
|
(97 |
) |
|
|
8 |
|
Interest rate swaps |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
Total |
|
$ |
16 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
30
Each reporting period, we recognize unrealized changes in the fair values of our investment in
14.2 million shares of Chevron common stock and the conversion option embedded in the debentures
exchangeable into shares of Chevron common stock. We calculate the fair value of our investment in
Chevron common stock using Chevrons published market price. The embedded option is not actively
traded in an established market. Therefore, we estimate its fair value using quotes obtained from a
broker for trades occurring near the valuation date. Because the exchangeable debentures are due in
August 2008, the embedded options recent fair value changes largely coincide with changes in the
market price of Chevrons common stock. As a result, when Chevrons common stock price has
increased from one valuation date to another, we have recognized a gain on our investment and a
loss on the embedded option. The inverse is also true.
The 2008 loss on our investment in Chevron common stock and gain on the embedded option were
directly attributable to a $7.97 decrease in the price per share of Chevrons common stock during
the first quarter of 2008. The 2007 gain on our investment in Chevron common stock and loss on the
embedded option were directly attributable to a $0.43 increase in the price per share of Chevrons
common stock during the first quarter of 2007.
Income Taxes
The following table presents our total income tax expense related to continuing operations and
a reconciliation of our effective income tax rate to the U.S. statutory income tax rate for the
first quarters of 2008 and 2007. The primary factors causing our effective rates to vary from 2007
to 2008, and differ from the U.S. statutory rate, are discussed below.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended Mach 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
|
|
|
|
|
|
|
Total income tax expense (In millions) |
|
$ |
241 |
|
|
$ |
264 |
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
|
35 |
% |
|
|
35 |
% |
Canadian statutory rate reductions |
|
|
(1 |
%) |
|
|
|
|
Other, primarily taxation on foreign operations |
|
|
(7 |
%) |
|
|
(3 |
%) |
|
|
|
|
|
|
|
Effective income tax rate |
|
|
27 |
% |
|
|
32 |
% |
|
|
|
|
|
|
|
In the first quarters of both 2008 and 2007, our effective income tax rate was lower than the
U.S. statutory income tax rate largely due to our foreign operations, which have statutory rates
lower than the U.S. statutory income tax rate. The 2008 effective income tax rate was lower than
the 2007 rate largely due to Canadian Federal and provincial statutory rate reductions enacted
subsequent to the first quarter of 2007. Additionally, in the first quarter of 2008, deferred
income taxes were reduced $7 million due to statutory rate reductions enacted by the British
Columbia and Saskatchewan provincial governments in Canada.
Earnings from Discontinued Operations
Our discontinued operations consist of our operations in Egypt, which were sold in the fourth
quarter of 2007, and our operations in West Africa, including Equatorial Guinea, Cote DIvoire,
Gabon and other countries in the region.
31
Following are the components of earnings from discontinued operations for the three months
ended March 31, 2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Earnings from discontinued operations before income taxes |
|
$ |
189 |
|
|
$ |
137 |
|
Income tax expense |
|
|
91 |
|
|
|
60 |
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
$ |
98 |
|
|
$ |
77 |
|
|
|
|
|
|
|
|
Earnings from discontinued operations increased $21 million in the first quarter of 2008. In
addition to variances caused by changes in production volumes and realized prices, our earnings
from discontinued operations in 2008 were impacted by other significant factors. As a result of
closing the sale of our Egyptian operations in the fourth quarter of 2007, we had no earnings from
our Egyptian operations in the first quarter of 2008. Egypt accounted for $11 million of earnings
from discontinued operations in the first quarter of 2007. Also, pursuant to accounting rules for
discontinued operations, we ceased recording DD&A in January 2007 for our West African operations.
During January 2007, prior to the decision to divest our West African properties, we recorded $16
million ($9 million after tax) of DD&A associated with these properties.
Capital Resources, Uses and Liquidity
The following discussion of liquidity and capital resources should be read in conjunction with
the consolidated statements of cash flows included in Part I, Item 1.
Sources and Uses of Cash
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
2,070 |
|
|
$ |
1,400 |
|
Sales of property and equipment |
|
|
105 |
|
|
|
25 |
|
Stock option exercises |
|
|
74 |
|
|
|
23 |
|
Net sales of short-term investments |
|
|
220 |
|
|
|
299 |
|
Other |
|
|
27 |
|
|
|
5 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
2,496 |
|
|
|
1,752 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(1,862 |
) |
|
|
(1,484 |
) |
Net repayments of debt |
|
|
(129 |
) |
|
|
(348 |
) |
Repurchases of common stock |
|
|
(64 |
) |
|
|
|
|
Dividends |
|
|
(73 |
) |
|
|
(64 |
) |
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(2,128 |
) |
|
|
(1,896 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) from continuing operations |
|
|
368 |
|
|
|
(144 |
) |
Increase from discontinued operations |
|
|
161 |
|
|
|
64 |
|
Effect of foreign exchange rates |
|
|
(19 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
$ |
510 |
|
|
$ |
(78 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
1,883 |
|
|
$ |
678 |
|
|
|
|
|
|
|
|
Short-term investments at end of period |
|
$ |
23 |
|
|
$ |
275 |
|
|
|
|
|
|
|
|
32
Operating Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash flow) continued to be the primary
source of capital and liquidity in the first quarter of 2008. Changes in operating cash flow are
largely due to the same factors that affect our net earnings, with the exception of those earnings
changes due to such noncash expenses as DD&A, financial instrument fair value changes and deferred
income tax expense. As a result, our operating cash flow increased in 2008 primarily due to the
increase in earnings as discussed in the Results of Operations section of this report.
During the first quarter of 2008, our operating cash flow was sufficient to fund our capital
expenditures. Additionally, during 2007, operating cash flow was used to fund substantially all of
our capital expenditures.
Other Sources of Cash
As needed, we utilize cash on hand and access our available credit under our credit facilities
and commercial paper program as sources of cash to supplement our operating cash flow.
Additionally, we sometimes acquire short-term investments to maximize our income on available cash
balances. As needed, we may reduce such short-term investment balances to further supplement our
operating cash flow.
During 2008, we reduced our short-term investment balances by $220 million. This source of
cash and our operating cash flow in excess of capital expenditures were primarily used to fund debt
repayments, common stock repurchases and dividends on common and preferred stock.
As of March 31, 2008, our credit facility borrowings had an average interest rate of 3.2% and
our commercial paper borrowings had an average interest rate of 3.3%.
During 2007, we reduced our short-term investment balances by $299 million to supplement our
operating cash flow and fund debt repayments.
Capital Expenditures
Following are the components of our capital expenditures for the first quarters of 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
959 |
|
|
$ |
726 |
|
U.S. Offshore |
|
|
244 |
|
|
|
168 |
|
Canada |
|
|
415 |
|
|
|
374 |
|
International |
|
|
110 |
|
|
|
91 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
1,728 |
|
|
|
1,359 |
|
Midstream |
|
|
104 |
|
|
|
83 |
|
Other |
|
|
30 |
|
|
|
42 |
|
|
|
|
|
|
|
|
Total capital expenditures |
|
$ |
1,862 |
|
|
$ |
1,484 |
|
|
|
|
|
|
|
|
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 $1.7 billion and
$1.4 billion in the first quarters of 2008 and 2007, respectively. Capital expenditures for our
midstream operations are primarily for the construction and expansion of natural gas processing
plants, natural gas pipeline systems and oil pipelines.
33
Our exploration and development capital expenditures increased $369 million in the first
quarter of 2008. The higher expenditures primarily relate to increased drilling activities in the
Barnett Shale, Gulf of Mexico and Carthage areas of the United States. Expenditures also increased
due to inflationary pressure driven by increased competition for field services.
Net 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
that we own prior to the debentures August 15, 2008 maturity date. We have the option, in lieu of
delivering shares of Chevron common stock, to pay exchanging debenture holders an amount of cash
equal to the market value of Chevron common stock. We paid $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.
During the first quarter of 2007, we repaid $348 million of commercial paper borrowings.
Repurchases of Common Stock
During the first quarter of 2008, we repurchased 0.8 million shares for $64 million, or $79.37
per share under our ongoing, annual repurchase program approved by our Board of Directors.
Dividends
Our common stock dividends were $71 million ($0.16 per share) and $62 million ($0.14 per
share) in the first quarter of 2008 and 2007, respectively. The higher dividend rate was the
primary cause of the increase in common dividends. We also paid $2 million of preferred stock
dividends in the first quarters of 2008 and 2007.
Liquidity
Our primary source of capital and liquidity has been our operating cash flow. Additionally, we
maintain revolving lines of credit and a commercial paper program which can be accessed as needed
to supplement operating cash flow. Other available sources of capital and liquidity include cash
and short-term investments on hand and the issuance of equity securities and long-term debt.
Another major source of near-term liquidity will be proceeds from the sales of our operations in
West Africa.
Operating Cash Flow
Our operating cash flow increased 49% to a record high of $2.3 billion in the first quarter of
2008. We expect operating cash flow to continue to be our primary source of liquidity. Our
operating cash flow is sensitive to many variables, the most volatile of which is pricing of the
oil, natural gas and NGLs produced. To mitigate some of the risk inherent in prices, we have
utilized various price collars to set minimum and maximum prices on a portion of our production. We
have also utilized various price swap contracts and fixed-price physical delivery contracts to fix
the price of a portion of our future oil and natural gas production. As disclosed in Item 7A.
Quantitative and Qualitative Disclosures of Market Risk of our 2007 Annual Report on Form 10-K,
approximately 64% of our estimated 2008 natural gas production and 12% of our estimated oil
production are subject to either price collars, swaps or fixed-price contracts. Additionally,
subsequent to the filing of our 2007 Annual Report, we have entered into additional gas price
collars, which represent approximately 10% of our estimated 2009 natural gas production. The key
terms of these 2009 price collars are included in Item 3. Quantitative and Qualitative Disclosures
of
Market Risk of this report.
34
Credit Availability
In April 2008, we extended the maturity of $2.0 billion of our existing $2.5 billion
five-year, syndicated, unsecured revolving line of credit (the Senior Credit Facility) from April
7, 2012 to April 7, 2013. Lenders representing $0.5 billion of the Senior Credit Facility did not
approve a maturity date extension. Therefore, the maturity date for $0.5 billion of the Senior
Credit Facility remains at April 7, 2012.
The Senior Credit Facility and our $1.5 billion 364-day, syndicated, unsecured revolving
senior credit facility contain only one material financial covenant. This covenant requires our
ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no
more than 65%. As of March 31, 2008, we were in compliance with this covenant. Our
debt-to-capitalization ratio at March 31, 2008, as calculated pursuant to the terms of the
agreement, was 23.3%.
As of March 31, 2008, our combined available capacity under our credit facilities was
approximately $1.5 billion. This available capacity is net of $920 million of outstanding
borrowings, $1.4 billion of outstanding commercial paper and $143 million of outstanding letters of
credit.
As of March 31, 2008, interest rates on our borrowings under our credit facilities and
commercial paper program averaged 3.2% and 3.3%, respectively.
Debt Ratings
During the first quarter of 2008, Standard and Poors upgraded our credit rating from BBB with
a positive outlook to BBB+ with a stable outlook. We are not aware of any potential downgrades or
changes contemplated by the other rating agencies as of April 30, 2008.
Property Divestitures
We have continued to make progress toward the divestitures of our West African operations. We
have entered into agreements to sell our operations in Equatorial Guinea, Gabon, Cote DIvoire and
other smaller countries for $2.6 billion. We are obtaining the necessary partner and government
approvals for these properties. We expect to complete the majority of these sales, including
Equatorial Guinea, during the second quarter of 2008.
Auction Rate Securities
At December 31, 2007, we held $372 million of auction rate securities, which are asset-backed
securities that have an auction rate reset feature. Our auction rate securities are rated AAAthe
highest ratingby one or more rating agencies and are collateralized by student loans that are
substantially guaranteed by the United States government. Although our auction rate securities
generally have contractual maturities of more than 20 years, the underlying interest rates on such
securities are scheduled to reset every seven to 28 days. Therefore, these auction rate securities
were generally priced and subsequently traded as short-term investments because of the interest
rate reset feature. As a result, we considered our auction rate securities to be short-term
investments at the end of 2007.
During the first quarter of 2008, we reduced our auction rate securities holdings to $152
million as of March 31, 2008. However, since February 8, 2008 we have experienced difficulty
selling our securities due to the failure of the auction mechanism, which provides liquidity to
these securities. An auction failure means that the parties wishing to sell securities could not do
so. The securities for which auctions have failed will continue to accrue interest and be auctioned
every seven to 28 days until the auction succeeds, the issuer calls the securities or the
securities mature.
Our auction rate securities holdings as of March 31, 2008 include $23 million of securities
that have been called at par value by the issuer effective May 21, 2008. Therefore, these called
securities continue to be considered short-term investments as of March 31, 2008. However, based on
continued auction failures and the current market for our auction
rate securities, we now consider the $129 million of securities that have not been called to
be long-term investments as of March 31, 2008 and generally not available for short-term liquidity
needs.
35
As of March 31, 2008 and December 31, 2007, we estimated the fair values of our short-term
auction rate securities using quoted market prices. However, due to the auction failures discussed
above and the lack of an active market for our long-term securities, quoted market prices for these
securities were not available as of March 31, 2008. Therefore, we used valuation techniques that
rely on unobservable inputs to estimate the fair values of our long-term auction rate securities as
of March 31, 2008. These inputs were based on the AAA credit rating of the securities, the
probability of full repayment of the securities considering the United States government guarantees
of the underlying student loans and the collection of all accrued interest to date. As a result of
using these inputs, we concluded the estimated fair values of our long-term auction rate securities
approximated the par values as of March 31, 2008. At this time, we do not believe the values of our
long-term securities are impaired.
Recently Issued Accounting Standards Not Yet Adopted
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards No. 141(R), Business Combinations, which replaces Statement No. 141.
Statement No. 141(R) retains the fundamental requirements of Statement No. 141 that an acquirer be
identified and the acquisition method of accounting (previously called the purchase method) be used
for all business combinations. Statement No. 141(R)s scope is broader than that of Statement No.
141, which applied only to business combinations in which control was obtained by transferring
consideration. By applying the acquisition method to all transactions and other events in which one
entity obtains control over one or more other businesses, Statement No. 141(R) improves the
comparability of the information about business combinations provided in financial reports.
Statement No. 141(R) establishes principles and requirements for how an acquirer recognizes and
measures identifiable assets acquired, liabilities assumed and any noncontrolling interest in the
acquiree, as well as any resulting goodwill. Statement No. 141(R) applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the first annual
reporting period beginning on or after December 15, 2008. We will evaluate how the new requirements
of Statement No. 141(R) would impact any business combinations completed in 2009 or thereafter.
In December 2007, the FASB also issued Statement of Financial Accounting Standards No. 160,
Noncontrolling Interests in Consolidated Financial Statementsan amendment of Accounting Research
Bulletin No. 51. A noncontrolling interest, sometimes called a minority interest, is the portion of
equity in a subsidiary not attributable, directly or indirectly, to a parent. Statement No. 160
establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and
for the deconsolidation of a subsidiary. Under Statement No. 160, noncontrolling interests in a
subsidiary must be reported as a component of consolidated equity separate from the parents
equity. Additionally, the amounts of consolidated net income attributable to both the parent and
the noncontrolling interest must be reported separately on the face of the income statement.
Statement No. 160 is effective for fiscal years beginning on or after December 15, 2008 and earlier
adoption is prohibited. We do not expect the adoption of Statement No. 160 to have a material
impact on our financial statements and related disclosures.
In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161,
Disclosures about Derivative Instruments and Hedging Activitiesan amendment of FASB Statement No.
133. Statement No. 161 requires additional disclosures about derivative and hedging activities and
is effective for fiscal years and interim periods beginning after November 15, 2008. We are
evaluating the impact the adoption of Statement No. 161 will have on our financial statement
disclosures. However, our adoption of Statement No. 161 will not affect our current accounting for
derivative and hedging activities.
36
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Subsequent to filing our 2007 Annual Report on Form 10-K, we entered into various price
collars to set minimum and maximum prices on approximately 10% of our expected 2009 gas production.
The key terms to our 2009 gas financial collar contracts are presented in the following table.
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas Price Collar Contracts |
|
|
|
|
|
|
Floor Price |
|
Ceiling Price |
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Floor |
|
Average |
|
Ceiling |
|
Average |
|
|
Volume |
|
Range |
|
Floor Price |
|
Range |
|
Ceiling Price |
Period |
|
(MMBtu/d) |
|
($/MMBtu) |
|
($/MMBtu) |
|
($/MMBtu) |
|
($/MMBtu) |
First quarter |
|
|
300,000 |
|
|
$ |
8.00 $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 $14.00 |
|
|
$ |
11.97 |
|
Second quarter |
|
|
300,000 |
|
|
$ |
8.00 $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 $14.00 |
|
|
$ |
11.97 |
|
Third quarter |
|
|
300,000 |
|
|
$ |
8.00 $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 $14.00 |
|
|
$ |
11.97 |
|
Fourth quarter |
|
|
300,000 |
|
|
$ |
8.00 $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 $14.00 |
|
|
$ |
11.97 |
|
2009 average |
|
|
300,000 |
|
|
$ |
8.00 $8.50 |
|
|
$ |
8.25 |
|
|
$ |
10.60 $14.00 |
|
|
$ |
11.97 |
|
The fair values of our oil and gas hedging instruments are largely determined by estimates of
the forward curves of relevant oil and gas price indexes. At March 31, 2008, a 10% increase in
these forward curves would have increased the net liabilities recorded for our 2008 and 2009
commodity hedging instruments by approximately $500 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, 2008 to ensure
that the information required to be disclosed by Devon in the reports that it files or submits
under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within
the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
There was no change in Devons internal control over financial reporting during the first
quarter of 2008 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
37
Part II. Other Information
Item 1. Legal Proceedings
There have been no material changes to the information included in Item 3. Legal Proceedings
in our 2007 Annual Report on Form 10-K.
Item 1A. Risk Factors
There have been no material changes to the information included in Item 1A. Risk Factors in
our 2007 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
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|
|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
Total Number of |
|
Maximum Number of |
|
|
Total |
|
|
|
|
|
Shares Purchased as |
|
Shares that May Yet |
|
|
Number of |
|
Average Price |
|
Part of Publicly |
|
Be Purchased Under |
|
|
Shares |
|
Paid per |
|
Announced Plans or |
|
the Plans or |
Period |
|
Purchased |
|
Share |
|
Programs(1) |
|
Programs(1) |
January |
|
|
808,100 |
|
|
$ |
79.37 |
|
|
|
808,100 |
|
|
|
53,991,900 |
|
February |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
53,991,900 |
|
March |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
|
53,991,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
808,100 |
|
|
$ |
79.37 |
|
|
|
808,100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Devons Board of Directors approved an ongoing, annual stock repurchase program to
minimize dilution resulting from restricted stock issued to, and options exercised by,
employees. In 2008, the repurchase program authorizes the repurchase of up to 4.8 million
shares or a cost of $422 million, whichever amount is reached first. All shares
repurchased in 2008 were made in conjunction with this plan. Also, in anticipation of the
completion of our West African divestitures, our Board of Directors approved a separate
program to repurchase up to 50 million shares. This program expires on December 31, 2009. |
Item 3. Defaults Upon Senior Securities
None.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
38
Item 6. Exhibits
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
|
|
|
Exhibit |
|
|
Number |
|
Description |
10.1
|
|
Fourth Amendment to Amended and Restated Credit Agreement
dated as of April 7, 2008, among Registrant as US Borrower,
Northstar Energy Corporation and Devon Canada Corporation
as the Canadian Borrowers, Bank of America, N.A.,
individually and as Administrative Agent and the Lenders
party thereto. |
|
|
|
31.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer
of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002. |
|
|
|
31.2
|
|
Certification of Danny J. Heatly, Vice President
Accounting and Chief Accounting Officer of Registrant,
pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer
of Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002. |
|
|
|
32.2
|
|
Certification of Danny J. Heatly, Vice President
Accounting and Chief Accounting Officer of Registrant,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. |
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 8, 2008 |
/s/ Danny J. Heatly
|
|
|
Danny J. Heatly |
|
|
Vice President Accounting and
Chief Accounting Officer |
|
|
39
INDEX TO EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Description |
10.1
|
|
Fourth Amendment to Amended and Restated Credit Agreement
dated as of April 7, 2008, among Registrant as US Borrower,
Northstar Energy Corporation and Devon Canada Corporation
as the Canadian Borrowers, Bank of America, N.A.,
individually and as Administrative Agent and the Lenders
party thereto. |
|
|
|
31.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer
of Registrant, pursuant to Rule 13a-14(a)/15d-14(a), as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002. |
|
|
|
31.2
|
|
Certification of Danny J. Heatly, Vice President
Accounting and Chief Accounting Officer of Registrant,
pursuant to Rule 13a-14(a)/15d-14(a), as adopted pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of J. Larry Nichols, Chief Executive Officer
of Registrant, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002. |
|
|
|
32.2
|
|
Certification of Danny J. Heatly, Vice President
Accounting and Chief Accounting Officer of Registrant,
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002. |
40