e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2011
or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission File Number 001-32318
DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State of other jurisdiction of incorporation or organization)
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73-1567067
(I.R.S. Employer identification No.) |
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20 North Broadway, Oklahoma City, Oklahoma
(Address of principal executive offices)
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73102-8260
(Zip code) |
Registrants telephone number, including area code: (405) 235-3611
Former name, former address and former fiscal year, if changed from last report: Not applicable
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act.
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
On April 25, 2011, 423.0 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
For the Quarterly Period Ended March 31, 2011
INDEX
2
DEFINITIONS
Measurements of Oil, Natural Gas and Natural Gas Liquids
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NGL or NGLs means natural gas liquids. |
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Oil includes crude oil and condensate. |
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Bbl means barrel of oil. One barrel equals 42 U.S. gallons. |
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MBbls means thousand barrels. |
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MMBbls means million barrels. |
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MBbls/d means thousand barrels per day. |
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Mcf means thousand cubic feet of natural gas. |
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MMcf means million cubic feet. |
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Bcf means billion cubic feet. |
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Bcfe means billion cubic feet equivalent. |
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MMcf/d means million cubic feet per day. |
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Boe means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. |
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MBoe means thousand Boe. |
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MMBoe means million Boe. |
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MBoe/d means thousand Boe per day. |
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Btu means British thermal units, a measure of heating value. |
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MMBtu means million Btu. |
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MMBtu/d means million Btu per day. |
Geographic Areas
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Canada means the operations of Devon encompassing oil and gas properties located in Canada. |
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International means the discontinued operations of Devon that encompass oil and gas
properties that lie outside the United States and Canada. |
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North America Onshore means the operations of Devon encompassing oil and gas
properties in the continental United States and Canada. |
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U.S. Offshore means the divested operations of Devon that encompassed oil and gas
properties in the Gulf of Mexico. |
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U.S. Onshore means the properties of Devon encompassing oil and gas properties in the
continental United States. |
Other
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Federal Funds Rate means the interest rate at which depository institutions lend
balances at the Federal Reserve to other depository institutions overnight. |
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Inside FERC refers to the publication Inside F.E.R.C.s Gas Market Report. |
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LIBOR means London Interbank Offered Rate. |
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NYMEX means New York Mercantile Exchange. |
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SEC means United States Securities and Exchange Commission. |
3
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements other than statements of historical facts included or incorporated by
reference in this report, including, without limitation, statements regarding our future financial
position, business strategy, budgets, projected revenues, projected costs and plans and objectives
of management for future operations, are forward-looking statements. Such forward-looking
statements are based on our examination of historical operating trends, the information used to
prepare the December 31, 2010 reserve reports and other data in our possession or available from
third parties. In addition, forward-looking statements generally can be identified by the use of
forward-looking terminology such as may, will, expect, intend, project, estimate,
anticipate, believe, or continue or similar terminology. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can give no assurance
that such expectations will prove to have been correct. Important factors that could cause actual
results to differ materially from our expectations include, but are not limited to, our assumptions
about:
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energy markets, including the supply and demand for oil, gas, NGLs and other products or
services, as well as the prices of oil, gas, NGLs and other products or services, including
regional pricing differentials; |
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production levels, including Canadian production subject to government royalties, which
fluctuate with prices and production; |
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reserve levels; |
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competitive conditions; |
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technology; |
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the availability of capital resources within the securities or capital markets and
related risks such as general credit, liquidity, market and interest-rate risks; |
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capital expenditure and other contractual obligations; |
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currency exchange rates; |
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the weather; |
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inflation; |
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the availability of goods and services; |
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drilling risks; |
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future processing volumes and pipeline throughput; |
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general economic conditions, whether internationally, nationally or in the jurisdictions
in which we or our subsidiaries conduct business; |
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public policy and government regulatory changes, including changes in royalty, production
tax and income tax regimes, changes in hydraulic fracturing regulation and changes in
environmental laws, regulation and liability; |
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terrorism; |
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occurrence of property acquisitions or divestitures; and |
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other factors disclosed in Devons 2010 Annual Report on Form 10-K under Item 1A. Risk
Factors, Item 2. Properties, Item 7. Managements Discussion and Analysis of Financial
Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures
About Market Risk. |
All subsequent written and oral forward-looking statements attributable to Devon, or persons
acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We
assume no duty to update or revise our forward-looking statements based on changes in internal
estimates or expectations or otherwise.
4
PART I. Financial Information
Item 1. Consolidated Financial Statements
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
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March 31, |
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December 31, |
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2011 |
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2010 |
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(Unaudited) |
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(In millions, except share data) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
1,311 |
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$ |
2,866 |
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Short-term investments |
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1,636 |
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145 |
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Accounts receivable |
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1,269 |
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1,202 |
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Current assets held for sale |
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533 |
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563 |
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Other current assets |
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850 |
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779 |
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Total current assets |
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5,599 |
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5,555 |
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Property and equipment, at cost: |
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Oil and gas, based on full cost accounting: |
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Subject to amortization |
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58,028 |
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56,012 |
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Not subject to amortization |
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3,508 |
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3,434 |
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Total oil and gas |
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61,536 |
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59,446 |
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Other |
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4,609 |
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4,429 |
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Total property and equipment, at cost |
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66,145 |
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63,875 |
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Less accumulated depreciation, depletion and amortization |
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(45,064 |
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(44,223 |
) |
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Property and equipment, net |
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21,081 |
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19,652 |
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Goodwill |
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6,151 |
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6,080 |
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Long-term assets held for sale |
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913 |
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859 |
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Other long-term assets |
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806 |
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781 |
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Total assets |
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$ |
34,550 |
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$ |
32,927 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable trade |
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$ |
1,353 |
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$ |
1,411 |
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Revenues and royalties due to others |
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639 |
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538 |
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Short-term debt |
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3,003 |
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1,811 |
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Current liabilities associated with assets held for sale |
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264 |
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305 |
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Other current liabilities |
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495 |
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518 |
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Total current liabilities |
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5,754 |
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4,583 |
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Long-term debt |
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3,800 |
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3,819 |
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Asset retirement obligations |
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1,468 |
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1,423 |
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Liabilities associated with assets held for sale |
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34 |
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26 |
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Other long-term liabilities |
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1,066 |
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1,067 |
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Deferred income taxes |
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3,199 |
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2,756 |
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Stockholders equity: |
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Common stock of $0.10 par value. Authorized 1.0 billion shares;
issued 425.2 million and 431.9 million shares in 2011 and 2010, respectively |
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43 |
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43 |
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Additional paid-in capital |
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5,028 |
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5,601 |
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Retained earnings |
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12,230 |
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11,882 |
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Accumulated other comprehensive earnings |
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1,951 |
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1,760 |
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Treasury stock, at cost. 0.3 million and 0.4 million shares in 2011 and 2010,
respectively |
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(23 |
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(33 |
) |
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Total stockholders equity |
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19,229 |
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19,253 |
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Commitments and contingencies (Note 10) |
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Total liabilities and stockholders equity |
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$ |
34,550 |
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$ |
32,927 |
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See accompanying notes to consolidated financial statements.
5
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
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Three Months |
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Ended March 31, |
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2011 |
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2010 |
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(Unaudited) |
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(In millions, except |
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per share amounts) |
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Revenues: |
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Oil, gas and NGL sales |
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$ |
1,860 |
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$ |
2,070 |
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Oil, gas and NGL derivatives |
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(168 |
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620 |
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Marketing and midstream revenues |
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455 |
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530 |
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Total revenues |
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2,147 |
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3,220 |
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Expenses and other, net: |
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Lease operating expenses |
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424 |
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414 |
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Taxes other than income taxes |
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108 |
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101 |
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Marketing and midstream operating costs and expenses |
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333 |
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397 |
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Depreciation, depletion and amortization of oil and gas properties |
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442 |
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426 |
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Depreciation and amortization of non-oil and gas properties |
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64 |
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63 |
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Accretion of asset retirement obligations |
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23 |
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26 |
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General and administrative expenses |
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130 |
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138 |
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Restructuring costs |
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(5 |
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Interest expense |
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81 |
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86 |
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Interest-rate and other financial instruments |
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(17 |
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(15 |
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Other, net |
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(16 |
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(4 |
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Total expenses and other, net |
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1,567 |
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1,632 |
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Earnings from continuing operations before income taxes |
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580 |
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1,588 |
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Income tax (benefit) expense: |
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Current |
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(89 |
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299 |
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Deferred |
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280 |
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215 |
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Total income tax expense |
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191 |
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514 |
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Earnings from continuing operations |
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389 |
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1,074 |
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Discontinued operations: |
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Earnings from discontinued operations before income taxes |
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30 |
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137 |
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Discontinued operations income tax expense |
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3 |
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19 |
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Earnings from discontinued operations |
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27 |
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118 |
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Net earnings |
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$ |
416 |
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$ |
1,192 |
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Basic net earnings per share: |
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Basic earnings from continuing operations per share |
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$ |
0.91 |
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$ |
2.40 |
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Basic earnings from discontinued operations per share |
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0.06 |
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0.27 |
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Basic net earnings per share |
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$ |
0.97 |
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$ |
2.67 |
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Diluted net earnings per share: |
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Diluted earnings from continuing operations per share |
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$ |
0.91 |
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$ |
2.39 |
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Diluted earnings from discontinued operations per share |
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0.06 |
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0.27 |
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Diluted net earnings per share |
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$ |
0.97 |
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$ |
2.66 |
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS
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Three Months |
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Ended March 31, |
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2011 |
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2010 |
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(Unaudited) |
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(In millions) |
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Net earnings |
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$ |
416 |
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$ |
1,192 |
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Foreign currency translation: |
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Change in cumulative translation adjustment |
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195 |
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222 |
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Foreign currency translation income tax expense |
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(10 |
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(12 |
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Foreign currency translation total |
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185 |
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210 |
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Pension and postretirement benefit plans: |
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Recognition of net actuarial loss and prior service cost in earnings |
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9 |
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8 |
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Pension and postretirement benefit plans income tax expense |
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(3 |
) |
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(3 |
) |
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Pension and postretirement benefit plans total |
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6 |
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5 |
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Other comprehensive earnings, net of tax |
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191 |
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215 |
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Comprehensive earnings |
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$ |
607 |
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$ |
1,407 |
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See accompanying notes to consolidated financial statements.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
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Accumulated |
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Additional |
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Other |
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Total |
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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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Shares |
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Amount |
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Capital |
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Earnings |
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Earnings |
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Stock |
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Equity |
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(Unaudited) |
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(In millions) |
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Three Months Ended March 31, 2011: |
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Balance as of December 31, 2010 |
|
|
432 |
|
|
$ |
43 |
|
|
$ |
5,601 |
|
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$ |
11,882 |
|
|
$ |
1,760 |
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|
$ |
(33 |
) |
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$ |
19,253 |
|
Net earnings |
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|
|
|
|
|
|
|
|
|
|
|
|
|
416 |
|
|
|
|
|
|
|
|
|
|
|
416 |
|
Other comprehensive earnings, net of tax |
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|
|
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|
|
191 |
|
|
|
|
|
|
|
191 |
|
Stock option exercises |
|
|
1 |
|
|
|
|
|
|
|
88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
88 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(696 |
) |
|
|
(696 |
) |
Common stock retired |
|
|
(8 |
) |
|
|
|
|
|
|
(706 |
) |
|
|
|
|
|
|
|
|
|
|
706 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(68 |
) |
|
|
|
|
|
|
|
|
|
|
(68 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2011 |
|
|
425 |
|
|
$ |
43 |
|
|
$ |
5,028 |
|
|
$ |
12,230 |
|
|
$ |
1,951 |
|
|
$ |
(23 |
) |
|
$ |
19,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009 |
|
|
447 |
|
|
$ |
45 |
|
|
$ |
6,527 |
|
|
$ |
7,613 |
|
|
$ |
1,385 |
|
|
$ |
|
|
|
$ |
15,570 |
|
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,192 |
|
|
|
|
|
|
|
|
|
|
|
1,192 |
|
Other comprehensive earnings, net of tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
215 |
|
|
|
|
|
|
|
215 |
|
Stock option exercises |
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Common stock repurchased |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
(2 |
) |
Common stock retired |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
Common stock dividends |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(72 |
) |
|
|
|
|
|
|
|
|
|
|
(72 |
) |
Share-based compensation |
|
|
|
|
|
|
|
|
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41 |
|
Share-based compensation tax benefits |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2010 |
|
|
447 |
|
|
$ |
45 |
|
|
$ |
6,577 |
|
|
$ |
8,733 |
|
|
$ |
1,600 |
|
|
$ |
|
|
|
$ |
16,955 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(Unaudited) |
|
|
|
(In millions) |
|
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
416 |
|
|
$ |
1,192 |
|
Earnings
from discontinued operations, net of tax |
|
|
(27 |
) |
|
|
(118 |
) |
Adjustments to reconcile earnings from continuing operations
to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
506 |
|
|
|
489 |
|
Deferred income tax expense |
|
|
280 |
|
|
|
215 |
|
Unrealized change in fair value of financial instruments |
|
|
253 |
|
|
|
(523 |
) |
Other noncash charges |
|
|
36 |
|
|
|
56 |
|
Net (increase) decrease in working capital |
|
|
(171 |
) |
|
|
50 |
|
Increase in long-term other assets |
|
|
(4 |
) |
|
|
(2 |
) |
Decrease in long-term other liabilities |
|
|
(23 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
Cash from operating activities continuing operations |
|
|
1,266 |
|
|
|
1,341 |
|
Cash from operating activities discontinued operations |
|
|
(6 |
) |
|
|
154 |
|
|
|
|
|
|
|
|
Net cash from operating activities |
|
|
1,260 |
|
|
|
1,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(1,827 |
) |
|
|
(1,247 |
) |
Purchases of short-term investments |
|
|
(1,636 |
) |
|
|
|
|
Redemptions of short-term investments |
|
|
145 |
|
|
|
|
|
Redemptions of long-term investments |
|
|
|
|
|
|
8 |
|
Proceeds from property and equipment divestitures |
|
|
5 |
|
|
|
1,257 |
|
Other |
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
Cash from investing activities continuing operations |
|
|
(3,322 |
) |
|
|
18 |
|
Cash from investing activities discontinued operations |
|
|
(52 |
) |
|
|
(107 |
) |
|
|
|
|
|
|
|
Net cash from investing activities |
|
|
(3,374 |
) |
|
|
(89 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Net commercial paper borrowings (repayments) |
|
|
1,197 |
|
|
|
(1,192 |
) |
Proceeds from stock option exercises |
|
|
88 |
|
|
|
8 |
|
Repurchases of common stock |
|
|
(706 |
) |
|
|
|
|
Dividends paid on common stock |
|
|
(68 |
) |
|
|
(72 |
) |
Excess tax benefits related to share-based compensation |
|
|
9 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Net cash from financing activities |
|
|
520 |
|
|
|
(1,253 |
) |
|
|
|
|
|
|
|
Effect of exchange rate changes on cash |
|
|
20 |
|
|
|
18 |
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
|
|
(1,574 |
) |
|
|
171 |
|
Cash and cash equivalents at beginning of period (including cash
related to assets held for sale) |
|
|
3,290 |
|
|
|
1,011 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period (including cash related
to assets held for sale) |
|
$ |
1,716 |
|
|
$ |
1,182 |
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
The accompanying unaudited consolidated financial statements and notes of Devon Energy
Corporation (Devon) have been prepared pursuant to the rules and regulations of the United States
Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures
normally included in financial statements prepared in accordance with accounting principles
generally accepted in the United States of America have been omitted. The accompanying consolidated
financial statements and notes should be read in conjunction with the consolidated financial
statements and notes included in Devons 2010 Annual Report on Form 10-K.
The unaudited interim consolidated financial statements furnished in this report reflect all
adjustments that are, in the opinion of management, necessary to a fair statement of Devons
financial position as of March 31, 2011 and Devons results of operations and cash flows for the
three-month periods ended March 31, 2011 and 2010.
2. Accounts Receivable
The components of accounts receivable include the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
|
December 31, 2010 |
|
|
|
(In millions) |
|
Oil, gas and NGL sales |
|
$ |
811 |
|
|
$ |
786 |
|
Marketing and midstream revenues |
|
|
204 |
|
|
|
165 |
|
Joint interest billings |
|
|
181 |
|
|
|
182 |
|
Other |
|
|
83 |
|
|
|
79 |
|
|
|
|
|
|
|
|
Gross accounts receivable |
|
|
1,279 |
|
|
|
1,212 |
|
Allowance for doubtful accounts |
|
|
(10 |
) |
|
|
(10 |
) |
|
|
|
|
|
|
|
Net accounts receivable |
|
$ |
1,269 |
|
|
$ |
1,202 |
|
|
|
|
|
|
|
|
3. Derivative Financial Instruments
Objectives and Strategies
Devon periodically enters into commodity and interest rate derivative financial instruments.
These instruments are used to manage the inherent uncertainty of future revenues due to oil, gas
and NGL price volatility and to manage exposure to interest rate volatility. Devon does not hold
or issue derivative financial instruments for speculative trading purposes and has elected not to
designate any of its derivative instruments for hedge accounting treatment.
Devons derivative financial instruments include financial price swaps, basis swaps, costless
price collars and call options. Under the terms of the price swaps, Devon receives a fixed price
for its production and pays a variable market price to the contract counterparty. For the basis
swaps, Devon receives a fixed differential between two regional gas index prices and pays a
variable differential on the same two index prices to the contract counterparty. The price collars
set a floor and ceiling price for the hedged production. If the applicable monthly price indices
are outside of the ranges set by the floor and ceiling prices in the various collars, Devon will
cash-settle the difference with the counterparty to the collars. Under the terms of the call
options, Devon sold to counterparties the right to purchase production at a predetermined price.
Devon periodically enters into interest rate swaps to manage its exposure to interest rate
volatility. Devons interest rate swaps include contracts in which Devon receives a fixed rate and
pays a variable rate on a total notional amount. Devon also has forward starting swaps. Under the
terms of the forward starting swaps, Devon will net settle these contracts in September 2011 or
sooner should Devon elect. The net settlement amount will be based upon Devon paying a fixed rate
and receiving a floating rate that is based upon the three-month LIBOR. The difference between the
fixed and floating rate will be applied to the notional amount for the 30-year period from
September 30, 2011 to September 30, 2041.
Counterparty Risk
By using derivative financial instruments to manage exposures to changes in commodity prices
and interest rates, Devon
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
exposes itself to credit risk and market risk. Credit risk is the failure
of the counterparty to perform under the terms of the derivative contract. To mitigate this risk,
the hedging instruments are placed with a number of counterparties whom Devon believes are minimal
credit risks. It is Devons policy to enter into derivative contracts only with investment grade
rated counterparties deemed by management to be competent and competitive market makers.
Additionally, Devons derivative contracts generally require cash collateral to be posted if either
its or the counterpartys credit rating falls below investment grade. The mark-to-market exposure
threshold, above which collateral must be posted, decreases as the debt rating falls further below
investment grade. Such thresholds generally range from zero to $50 million for the majority of
Devons contracts. As of March 31, 2011, the credit ratings of all Devons counterparties were
investment grade.
Commodity Derivatives
As of March 31, 2011, Devon had the following open oil derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
Period |
|
Price Swaps |
|
|
Price Collars |
|
|
Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
|
Volume |
|
|
Average Floor Price |
|
|
Average Ceiling Price |
|
|
Volume |
|
|
Average Price |
|
Period |
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
Q2-Q4 2011 |
|
|
|
|
|
|
|
|
|
|
45,000 |
|
|
$ |
75.00 |
|
|
$ |
108.89 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
Q1-Q4 2012 |
|
|
9,000 |
|
|
$ |
104.20 |
|
|
|
35,000 |
|
|
$ |
82.14 |
|
|
$ |
126.42 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
As of March 31, 2011, Devon had the following open natural gas derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
Period |
|
Price Swaps |
|
|
Price Collars |
|
|
Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
|
Volume |
|
|
Average Floor Price |
|
|
Average Ceiling Price |
|
|
Volume |
|
|
Average Price |
|
Period |
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
|
($/MMBtu) |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Q2 2011 |
|
|
912,500 |
|
|
$ |
5.24 |
|
|
|
350,000 |
|
|
$ |
4.18 |
|
|
$ |
4.68 |
|
|
|
|
|
|
|
|
|
Q3 2011 |
|
|
712,500 |
|
|
$ |
5.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2011 |
|
|
712,500 |
|
|
$ |
5.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1-Q4 2012 |
|
|
130,000 |
|
|
$ |
5.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
487,500 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
Differential to |
|
|
|
|
|
|
|
Volume |
|
|
Henry Hub |
|
Production Period |
|
Index |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Q2-Q4 2011 |
|
Panhandle Eastern Pipeline |
|
|
150,000 |
|
|
$ |
0.33 |
|
As of March 31, 2011, Devon had the following open NGL derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
Volume |
|
|
Differential to WTI |
|
Production Period |
|
Pay |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
Q2-Q4 2011 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
9.75 |
|
Q1-Q4 2012 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
10.10 |
|
Q1-Q4 2013 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
6.80 |
|
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Interest Rate Derivatives
As of March 31, 2011, Devon had the following open interest rate swap derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed-to-Floating Swaps |
|
|
|
Fixed Rate |
|
|
Variable |
|
|
|
|
Notional |
|
Received |
|
|
Rate Paid |
|
|
Expiration |
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
$300 |
|
|
4.30 |
% |
|
Six month LIBOR |
|
July 18, 2011 |
100 |
|
|
1.90 |
% |
|
Federal funds rate |
|
August 3, 2012 |
500 |
|
|
3.90 |
% |
|
Federal funds rate |
|
July 18, 2013 |
250 |
|
|
3.85 |
% |
|
Federal funds rate |
|
July 22, 2013 |
|
|
|
|
|
|
|
|
|
|
$1,150 |
|
|
3.82 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward Starting Swaps |
|
|
|
Fixed Rate |
|
|
Variable |
|
|
|
|
Notional |
|
Paid |
|
|
Rate Received |
|
|
Expiration |
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
$950 |
|
|
3.92 |
% |
|
Three month LIBOR |
|
September 30, 2011 |
Financial Statement Presentation
The following table presents the derivative fair values included in the accompanying
consolidated balance sheets.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Caption |
|
|
March 31, 2011 |
|
|
December 31, 2010 |
|
|
|
|
|
|
|
(In millions) |
|
Asset derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Other current assets |
|
$ |
183 |
|
|
$ |
248 |
|
Commodity derivatives |
|
Other long-term assets |
|
|
2 |
|
|
|
1 |
|
Interest rate derivatives |
|
Other current assets |
|
|
112 |
|
|
|
100 |
|
Interest rate derivatives |
|
Other long-term assets |
|
|
29 |
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
|
Total asset derivatives |
|
|
|
|
|
$ |
326 |
|
|
$ |
389 |
|
|
|
|
|
|
|
|
|
|
|
|
Liability derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Other current liabilities |
|
$ |
225 |
|
|
$ |
50 |
|
Commodity derivatives |
|
Other long-term liabilities |
|
|
157 |
|
|
|
142 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liability derivatives |
|
|
|
|
|
$ |
382 |
|
|
$ |
192 |
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents the cash settlements and unrealized gains and losses on fair
value changes included in the accompanying consolidated statements of operations associated with
these derivative financial instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
|
|
|
|
Ended March 31, |
|
|
|
Statement of Operations Caption |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
(In millions) |
|
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Oil, gas and NGL derivatives |
|
$ |
86 |
|
|
$ |
96 |
|
Interest rate derivatives |
|
Interest-rate and other financial instruments |
|
|
16 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
|
|
|
|
102 |
|
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized (losses) gains: |
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivatives |
|
Oil, gas and NGL derivatives |
|
|
(254 |
) |
|
|
524 |
|
Interest rate derivatives |
|
Interest-rate and other financial instruments |
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total unrealized (losses) gains |
|
|
|
|
|
|
(253 |
) |
|
|
523 |
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) gain recognized on
statement of operations |
|
|
|
|
|
$ |
(151 |
) |
|
$ |
635 |
|
|
|
|
|
|
|
|
|
|
|
|
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
4. Other Current Assets
The components of other current assets include the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, 2011 |
|
|
December 31, 2010 |
|
|
|
(In millions) |
|
Income taxes receivable |
|
$ |
374 |
|
|
$ |
270 |
|
Derivative financial instruments |
|
|
295 |
|
|
|
348 |
|
Inventories |
|
|
116 |
|
|
|
120 |
|
Other |
|
|
65 |
|
|
|
41 |
|
|
|
|
|
|
|
|
Other current assets |
|
$ |
850 |
|
|
$ |
779 |
|
|
|
|
|
|
|
|
5. Goodwill
During the first three months of 2011, Devons Canadian goodwill increased $71 million
entirely due to foreign currency translation.
6. Debt
Credit Lines
Devon has a $2,650 million syndicated, unsecured revolving line of credit (the Senior Credit
Facility). As of March 31, 2011, Devon had no borrowings under the Senior Credit Facility.
The Senior Credit Facility contains only one material financial covenant. This covenant
requires Devons ratio of total funded debt to total capitalization to be less than 65 percent. The
credit agreement contains definitions of total funded debt and total capitalization that include
adjustments to the respective amounts reported in the consolidated financial statements. Also,
total capitalization is adjusted to add back noncash financial writedowns such as full cost ceiling
impairments or goodwill impairments. As of March 31, 2011, Devon was in compliance with this
covenant. Devons debt-to-capitalization ratio at March 31, 2011, as calculated pursuant to the
terms of the agreement, was 17.7 percent.
Commercial Paper
In March 2011, Devons Board of Directors authorized an increase in its commercial paper
program from $2.2 billion to $5.0 billion. Commercial paper debt generally has a maturity of
between one and 90 days, although it can have a maturity of up to 365 days, and bears interest at
rates agreed to at the time of the borrowing. The interest rate is based on a standard index such
as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.
Although Devon began and ended the first quarter of 2011 with approximately $3.4 billion of
cash and short-term investments, the vast majority of this amount consists of proceeds from its
2010 International divestitures. Based on Devons evaluation of future cash needs across its
operations in the United States and Canada, these proceeds remain outside of the United States.
Consequently, during the first quarter of 2011, Devon borrowed $1,197 million of commercial
paper in the United States primarily to fund capital expenditures, common stock repurchases and
dividends in excess of cash flow generated by its United States operating activities. As of March
31, 2011, Devons average borrowing rate on its $1,197 million of commercial paper borrowings was
0.30 percent.
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Asset Retirement Obligations
The schedule below summarizes changes in Devons asset retirement obligations.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Asset retirement obligations as of beginning of period |
|
$ |
1,497 |
|
|
$ |
1,513 |
|
Liabilities incurred |
|
|
11 |
|
|
|
16 |
|
Liabilities settled |
|
|
(18 |
) |
|
|
(47 |
) |
Revision of estimated obligation |
|
|
3 |
|
|
|
205 |
|
Liabilities assumed by others |
|
|
|
|
|
|
(8 |
) |
Accretion expense on discounted obligation |
|
|
23 |
|
|
|
26 |
|
Foreign currency translation adjustment |
|
|
21 |
|
|
|
22 |
|
|
|
|
|
|
|
|
Asset retirement obligations as of end of period |
|
|
1,537 |
|
|
|
1,727 |
|
Less current portion |
|
|
69 |
|
|
|
90 |
|
|
|
|
|
|
|
|
Asset retirement obligations, long-term |
|
$ |
1,468 |
|
|
$ |
1,637 |
|
|
|
|
|
|
|
|
During the first quarter of 2010, Devon recognized a revision to its asset retirement
obligations totaling $205 million. The increase was primarily due to an overall increase in
abandonment cost estimates and a decrease in the discount rate used to calculate the present value
of the obligations.
8. Retirement Plans
The following table presents the components of net periodic benefit cost for Devons pension
and other postretirement benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits |
|
|
Other Postretirement Benefits |
|
|
|
Three Months |
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Net periodic benefit cost: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Service cost |
|
$ |
9 |
|
|
$ |
8 |
|
|
$ |
|
|
|
$ |
|
|
Interest cost |
|
|
15 |
|
|
|
14 |
|
|
|
1 |
|
|
|
1 |
|
Expected return on plan assets |
|
|
(10 |
) |
|
|
(9 |
) |
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
Net actuarial loss |
|
|
8 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost |
|
$ |
23 |
|
|
$ |
21 |
|
|
$ |
1 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon previously disclosed in its financial statements for the year ended December 31, 2010,
that it expected to contribute $84 million to its qualified pension plans in 2011. Devon now
expects to contribute $346 million to its qualified pension plans in 2011, including $32 million
that was contributed in the first quarter. The increase in Devons 2011 estimated contribution is
due to increased discretionary funding.
9. Stockholders Equity
Stock Repurchases
During the first quarter of 2011, Devon repurchased 8.1 million common shares under its $3.5
billion stock repurchase program announced in 2010 for $696 million, or $85.95 per share. Through
the end of the first quarter of 2011, Devon had repurchased 26.4 million common shares for $1.9
billion, or $71.83 per share, under this program, which expires December 31, 2011.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Dividends
Devon paid common stock dividends of $68 million and $72 million (quarterly rates of $0.16 per
share) in the first quarter of 2011 and 2010, respectively. In March 2011, Devon announced an
increase of its quarterly cash dividend to $0.17 per share that will begin in the second quarter of
2011.
10. 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.
Environmental Matters
Devon is subject to certain laws and regulations relating to environmental remediation
activities associated with past operations, such as the Comprehensive Environmental Response,
Compensation, and Liability Act and similar state statutes. In response to liabilities associated
with these activities, loss accruals primarily consist of estimated uninsured costs associated with
remediation. Devons monetary exposure for environmental matters is not expected to be material.
Royalty Matters
Numerous natural gas producers and related parties, including Devon, have been named in
various lawsuits alleging violation of the federal False Claims Act. The suits allege that the
producers and related parties used below-market prices, improper deductions, improper measurement
techniques and transactions with affiliates, which resulted in underpayment of royalties in
connection with natural gas and NGLs produced and sold from federal and Indian owned or controlled
lands. Devon does not currently believe that it is subject to material exposure with respect to
such royalty matters.
Other Matters
Devon is involved in other various routine legal proceedings incidental to its business.
However, to Devons knowledge, there were no other material pending legal proceedings to which
Devon is a party or to which any of its property is subject.
11. Fair Value Measurements
Certain of Devons assets and liabilities are reported at fair value in the accompanying
consolidated balance sheets. Such assets and liabilities include amounts for both financial and
non-financial instruments. The following tables provide carrying value and fair value measurement
information for Devons financial assets and liabilities.
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The carrying values of cash and cash equivalents, accounts receivable, other current
receivables, accounts payable and other current payables and accrued expenses included in the
accompanying consolidated balance sheets approximated fair value at March 31, 2011 and December 31,
2010. These assets and liabilities are not presented in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using: |
|
|
|
|
|
|
|
|
|
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
|
Carrying Amount |
|
|
Total Fair Value |
|
|
Inputs |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
March 31, 2011 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
1,636 |
|
|
$ |
1,636 |
|
|
$ |
1,636 |
|
|
$ |
|
|
|
$ |
|
|
Long-term investments |
|
$ |
94 |
|
|
$ |
94 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
94 |
|
Commodity derivatives |
|
$ |
185 |
|
|
$ |
185 |
|
|
$ |
|
|
|
$ |
185 |
|
|
$ |
|
|
Commodity derivatives |
|
$ |
(382 |
) |
|
$ |
(382 |
) |
|
$ |
|
|
|
$ |
(382 |
) |
|
$ |
|
|
Interest rate derivatives |
|
$ |
141 |
|
|
$ |
141 |
|
|
$ |
|
|
|
$ |
141 |
|
|
$ |
|
|
Debt |
|
$ |
(6,803 |
) |
|
$ |
(7,726 |
) |
|
$ |
(1,197 |
) |
|
$ |
(6,410 |
) |
|
$ |
(119 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
145 |
|
|
$ |
145 |
|
|
$ |
145 |
|
|
$ |
|
|
|
$ |
|
|
Long-term investments |
|
$ |
94 |
|
|
$ |
94 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
94 |
|
Commodity derivatives |
|
$ |
249 |
|
|
$ |
249 |
|
|
$ |
|
|
|
$ |
249 |
|
|
$ |
|
|
Commodity derivatives |
|
$ |
(192 |
) |
|
$ |
(192 |
) |
|
$ |
|
|
|
$ |
(192 |
) |
|
$ |
|
|
Interest rate derivatives |
|
$ |
140 |
|
|
$ |
140 |
|
|
$ |
|
|
|
$ |
140 |
|
|
$ |
|
|
Debt |
|
$ |
(5,630 |
) |
|
$ |
(6,629 |
) |
|
$ |
|
|
|
$ |
(6,485 |
) |
|
$ |
(144 |
) |
Devons Level 3 fair value measurements included in the table above relate to certain
long-term investments and a non-interest bearing promissory note. Included below is a summary of
the changes in Devons Level 3 fair value measurements during the first three months of 2011 and
2010.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Long-term investments balance at beginning of period |
|
$ |
94 |
|
|
$ |
115 |
|
Redemptions of principal |
|
|
|
|
|
|
(8 |
) |
|
|
|
|
|
|
|
Long-term investments balance at end of period |
|
$ |
94 |
|
|
$ |
107 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Debt balance at beginning of period |
|
$ |
(144 |
) |
|
$ |
|
|
Foreign exchange translation adjustment |
|
|
(3 |
) |
|
|
|
|
Accretion of promissory note |
|
|
(1 |
) |
|
|
|
|
Redemptions of principal |
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
Debt balance at end of period |
|
$ |
(119 |
) |
|
$ |
|
|
|
|
|
|
|
|
|
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
12. Restructuring Costs
In the fourth quarter of 2009, Devon announced plans to divest its offshore assets. As of
March 31, 2011, Devon had divested all of its U.S. Offshore assets and a significant part of its
International assets. Devon has entered into agreements to sell its remaining offshore assets in
Brazil and Angola and is waiting for the respective governments to approve the divestitures.
Through the end of the first quarter of 2011, Devon had incurred $207 million of restructuring
costs associated with these divestitures. This amount is comprised of $127 million of employee
severance costs, $77 million associated with abandoned office leases and $3 million of other
miscellaneous costs.
Financial Statement Presentation
The schedule below summarizes activity and balances associated with Devons restructuring
liabilities. There was no activity during the first quarter of 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
Discontinued Operations |
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
Other Current |
|
|
Long-Term |
|
|
|
|
|
|
Other Current |
|
|
Long-Term |
|
|
|
|
|
|
Liabilities |
|
|
Liabilities |
|
|
Total |
|
|
Liabilities |
|
|
Liabilities |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2010 |
|
$ |
31 |
|
|
$ |
51 |
|
|
$ |
82 |
|
|
$ |
16 |
|
|
$ |
|
|
|
$ |
16 |
|
Cash severance settled |
|
|
(8 |
) |
|
|
|
|
|
|
(8 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
Lease obligations settled |
|
|
(3 |
) |
|
|
(4 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Cash severance revision |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Lease obligations revision |
|
|
(3 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2011 |
|
$ |
17 |
|
|
$ |
46 |
|
|
$ |
63 |
|
|
$ |
21 |
|
|
$ |
|
|
|
$ |
21 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2010 |
|
$ |
61 |
|
|
$ |
|
|
|
$ |
61 |
|
|
$ |
23 |
|
|
$ |
|
|
|
$ |
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The schedule below summarizes the components of restructuring costs in the accompanying 2011
consolidated statement of operations. No restructuring costs were recorded in the three months
ended March 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2011 |
|
|
|
Continuing |
|
|
Discontinued |
|
|
|
|
|
|
Operations |
|
|
Operations |
|
|
Total |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash severance |
|
$ |
|
|
|
$ |
6 |
|
|
$ |
6 |
|
Share-based awards |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
Lease obligations |
|
|
(4 |
) |
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
Restructuring costs |
|
$ |
(5 |
) |
|
$ |
6 |
|
|
$ |
1 |
|
|
|
|
|
|
|
|
|
|
|
13. Discontinued Operations
Revenues related to Devons discontinued operations totaled $43 million and $212 million in
the three months ended March 31, 2011 and March 31, 2010, respectively. Earnings from discontinued
operations before income taxes totaled $30 million and $137 million in the three months ended March
31, 2011 and March 31, 2010, respectively.
17
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.
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Cash and cash equivalents |
|
$ |
405 |
|
|
$ |
424 |
|
Accounts receivable |
|
|
18 |
|
|
|
43 |
|
Other current assets |
|
|
110 |
|
|
|
96 |
|
|
|
|
|
|
|
|
Current assets |
|
$ |
533 |
|
|
$ |
563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property and equipment, net |
|
$ |
875 |
|
|
$ |
848 |
|
Other long-term assets |
|
|
38 |
|
|
|
11 |
|
|
|
|
|
|
|
|
Total long-term assets |
|
$ |
913 |
|
|
$ |
859 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
229 |
|
|
$ |
260 |
|
Other current liabilities |
|
|
35 |
|
|
|
45 |
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
264 |
|
|
$ |
305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term liabilities |
|
$ |
34 |
|
|
$ |
26 |
|
|
|
|
|
|
|
|
14. Earnings Per Share
The following table reconciles earnings from continuing operations and common shares
outstanding used in the calculations of basic and diluted earnings per share.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings |
|
|
|
Earnings |
|
|
Common Shares |
|
|
per Share |
|
|
|
(In millions, except per share amounts) |
|
Three Months Ended March 31, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
389 |
|
|
|
428 |
|
|
|
|
|
Attributable to participating securities |
|
|
(4 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
385 |
|
|
|
423 |
|
|
$ |
0.91 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
385 |
|
|
|
425 |
|
|
$ |
0.91 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
1,074 |
|
|
|
447 |
|
|
|
|
|
Attributable to participating securities |
|
|
(13 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per share |
|
|
1,061 |
|
|
|
441 |
|
|
$ |
2.40 |
|
Dilutive effect of potential common shares issuable
upon the exercise of outstanding stock options
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share |
|
$ |
1,061 |
|
|
|
443 |
|
|
$ |
2.39 |
|
|
|
|
|
|
|
|
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution
calculations because the options are antidilutive. These excluded options totaled 3.1 million and
6.4 million during the three-month periods ended March 31, 2011 and 2010, respectively.
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
15. Segment Information
Devon manages its North American onshore operations through distinct operating segments, or
divisions, which are defined primarily by geographic areas. For financial reporting purposes, Devon
aggregates its United States divisions into one reporting segment due to the similar nature of the
businesses. However, Devons Canadian and International divisions are reported as separate
reporting segments primarily due to significant differences in the respective regulatory
environments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
International |
|
|
Total |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
As of March 31, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
2,641 |
|
|
$ |
2,425 |
|
|
$ |
533 |
|
|
$ |
5,599 |
|
Property and equipment, net |
|
|
13,314 |
|
|
|
7,767 |
|
|
|
|
|
|
|
21,081 |
|
Goodwill |
|
|
3,046 |
|
|
|
3,105 |
|
|
|
|
|
|
|
6,151 |
|
Other assets |
|
|
431 |
|
|
|
375 |
|
|
|
913 |
|
|
|
1,719 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
19,432 |
|
|
$ |
13,672 |
|
|
$ |
1,446 |
|
|
$ |
34,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
2,996 |
|
|
$ |
2,494 |
|
|
$ |
264 |
|
|
$ |
5,754 |
|
Long-term debt |
|
|
2,502 |
|
|
|
1,298 |
|
|
|
|
|
|
|
3,800 |
|
Asset retirement obligations |
|
|
565 |
|
|
|
903 |
|
|
|
|
|
|
|
1,468 |
|
Other liabilities |
|
|
1,002 |
|
|
|
64 |
|
|
|
34 |
|
|
|
1,100 |
|
Deferred income taxes |
|
|
1,896 |
|
|
|
1,303 |
|
|
|
|
|
|
|
3,199 |
|
Stockholders equity |
|
|
10,471 |
|
|
|
7,610 |
|
|
|
1,148 |
|
|
|
19,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
19,432 |
|
|
$ |
13,672 |
|
|
$ |
1,446 |
|
|
$ |
34,550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Three Months Ended March 31, 2011: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
1,212 |
|
|
$ |
648 |
|
|
$ |
1,860 |
|
Oil, gas and NGL derivatives |
|
|
(168 |
) |
|
|
|
|
|
|
(168 |
) |
Marketing and midstream revenues |
|
|
423 |
|
|
|
32 |
|
|
|
455 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
1,467 |
|
|
|
680 |
|
|
|
2,147 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
208 |
|
|
|
216 |
|
|
|
424 |
|
Taxes other than income taxes |
|
|
94 |
|
|
|
14 |
|
|
|
108 |
|
Marketing and midstream operating costs and expenses |
|
|
308 |
|
|
|
25 |
|
|
|
333 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
260 |
|
|
|
182 |
|
|
|
442 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
58 |
|
|
|
6 |
|
|
|
64 |
|
Accretion of asset retirement obligations |
|
|
9 |
|
|
|
14 |
|
|
|
23 |
|
General and administrative expenses |
|
|
91 |
|
|
|
39 |
|
|
|
130 |
|
Restructuring costs |
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
Interest expense |
|
|
37 |
|
|
|
44 |
|
|
|
81 |
|
Interest-rate and other financial instruments |
|
|
(17 |
) |
|
|
|
|
|
|
(17 |
) |
Other, net |
|
|
(14 |
) |
|
|
(2 |
) |
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
1,029 |
|
|
|
538 |
|
|
|
1,567 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
438 |
|
|
|
142 |
|
|
|
580 |
|
Income tax (benefit) expense: |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(88 |
) |
|
|
(1 |
) |
|
|
(89 |
) |
Deferred |
|
|
243 |
|
|
|
37 |
|
|
|
280 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
155 |
|
|
|
36 |
|
|
|
191 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
283 |
|
|
$ |
106 |
|
|
$ |
389 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
1,250 |
|
|
$ |
532 |
|
|
$ |
1,782 |
|
Revision of future asset retirement obligations |
|
|
(11 |
) |
|
|
14 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,239 |
|
|
$ |
546 |
|
|
$ |
1,785 |
|
|
|
|
|
|
|
|
|
|
|
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
Canada |
|
|
Total |
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Three Months Ended March 31, 2010: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
|
$ |
1,370 |
|
|
$ |
700 |
|
|
$ |
2,070 |
|
Oil, gas and NGL derivatives |
|
|
625 |
|
|
|
(5 |
) |
|
|
620 |
|
Marketing and midstream revenues |
|
|
496 |
|
|
|
34 |
|
|
|
530 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
2,491 |
|
|
|
729 |
|
|
|
3,220 |
|
|
|
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses |
|
|
224 |
|
|
|
190 |
|
|
|
414 |
|
Taxes other than income taxes |
|
|
90 |
|
|
|
11 |
|
|
|
101 |
|
Marketing and midstream operating costs and expenses |
|
|
369 |
|
|
|
28 |
|
|
|
397 |
|
Depreciation, depletion and amortization of oil and gas
properties |
|
|
261 |
|
|
|
165 |
|
|
|
426 |
|
Depreciation and amortization of non-oil and gas properties |
|
|
56 |
|
|
|
7 |
|
|
|
63 |
|
Accretion of asset retirement obligations |
|
|
13 |
|
|
|
13 |
|
|
|
26 |
|
General and administrative expenses |
|
|
108 |
|
|
|
30 |
|
|
|
138 |
|
Interest expense |
|
|
30 |
|
|
|
56 |
|
|
|
86 |
|
Interest-rate and other financial instruments |
|
|
(15 |
) |
|
|
|
|
|
|
(15 |
) |
Other, net |
|
|
(3 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
1,133 |
|
|
|
499 |
|
|
|
1,632 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations before income taxes |
|
|
1,358 |
|
|
|
230 |
|
|
|
1,588 |
|
Income tax expense (benefit): |
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
214 |
|
|
|
85 |
|
|
|
299 |
|
Deferred |
|
|
235 |
|
|
|
(20 |
) |
|
|
215 |
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
449 |
|
|
|
65 |
|
|
|
514 |
|
|
|
|
|
|
|
|
|
|
|
Earnings from continuing operations |
|
$ |
909 |
|
|
$ |
165 |
|
|
$ |
1,074 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, before revision of future asset
retirement
obligations |
|
$ |
1,033 |
|
|
$ |
370 |
|
|
$ |
1,403 |
|
Revision of future asset retirement obligations |
|
|
83 |
|
|
|
122 |
|
|
|
205 |
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures, continuing operations |
|
$ |
1,116 |
|
|
$ |
492 |
|
|
$ |
1,608 |
|
|
|
|
|
|
|
|
|
|
|
16. Supplemental Information to Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Net (increase) decrease in working capital: |
|
|
|
|
|
|
|
|
Increase in accounts receivable |
|
$ |
(60 |
) |
|
$ |
(78 |
) |
Increase in other current assets |
|
|
(110 |
) |
|
|
(2 |
) |
Increase (decrease) in accounts payable |
|
|
45 |
|
|
|
(29 |
) |
Increase in revenues and royalties due to others |
|
|
100 |
|
|
|
58 |
|
(Decrease) increase in other current liabilities |
|
|
(146 |
) |
|
|
101 |
|
|
|
|
|
|
|
|
Net (increase) decrease in working capital |
|
$ |
(171 |
) |
|
$ |
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplementary cash flow data total operations: |
|
|
|
|
|
|
|
|
Interest paid (net of capitalized interest) |
|
$ |
137 |
|
|
$ |
137 |
|
Income taxes paid |
|
$ |
9 |
|
|
$ |
50 |
|
21
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis addresses material changes in our results of operations
and capital resources and uses for the three-month period ended March 31, 2011, compared to the
three-month period ended March 31, 2010, and in our financial condition and liquidity since
December 31, 2010. For information regarding our critical accounting policies and estimates, see
our 2010 Annual Report on Form 10-K under Item 7. Managements Discussion and Analysis of
Financial Condition and Results of Operations.
Financial Overview
During the first three months of 2011 and 2010, we generated net earnings of $416 million, or
$0.97 per diluted share, and $1.2 billion, or $2.66 per diluted share, for the respective periods.
The primary drivers for the decrease in earnings were unrealized gains recognized on our commodity
hedges in 2010 and lower gas prices in 2011. In addition, the 2010 results include operating
earnings from our offshore properties that were divested subsequent to the first quarter of 2010.
Key measures of our financial performance for the first three months of 2011 compared to the
first three months of 2010 are summarized below:
|
|
|
North America Onshore oil and NGL production increased 11% to 19 MMBbls. |
|
|
|
North America Onshore gas production increased 5% to 228 Bcf. |
|
|
|
The combined realized price without hedges for oil, gas and NGLs decreased 11% to $32.86
per Boe. |
|
|
|
Oil, gas and NGL derivatives incurred a net loss of $168 million in the first three
months of 2011 and generated a net gain of $620 million in the first three months of 2010.
Included in these amounts were cash receipts of $86 million and $96 million, respectively. |
|
|
|
Marketing and midstream operating profit decreased 9% to $122 million. |
|
|
|
Per unit operating costs increased 1% to $7.48 per Boe. |
|
|
|
Operating cash flow decreased 16% to $1.3 billion. |
|
|
|
Capital spending totaled approximately $1.8 billion in the first quarter of
2011. |
Our performance and the proceeds from our previous offshore divestitures have allowed us to
maintain a robust level of liquidity. As of March 31, 2011, we held $3.4 billion in cash and
short-term investments, access to short-term commercial paper
borrowings and our $2.7 billion credit facility. With this
liquidity, we continue executing our exploration and development programs, with a focus on growing
our liquids production, and repurchasing common shares under our $3.5 billion share repurchase
program. Through April 25, 2011, we had repurchased 28.3 million shares for $2.1 billion, or $72.98
per share.
First-Quarter Operating Highlights
|
|
|
Production from our Cana-Woodford Shale play averaged a record
162 million cubic feet of natural gas equivalent per day in the
first quarter of 2011. This represents a 120 percent increase
compared to the first-quarter of 2010. |
|
|
|
In the Permian Basin, oil and natural gas liquids production increased 17 percent
over the first-quarter 2010. In aggregate, liquids production accounted for nearly 75
percent of the 44,000 equivalent barrels per day produced in the Permian Basin during
the first quarter. |
|
|
|
In Canada, we plan to commence steam injection at Jackfish 2 in May with first
production expected by year-end. At full production, Jackfish 2 is expected to produce
35,000 barrels per day before royalties for more than 20 years. |
|
|
|
Immediately adjacent to our Jackfish lease, we successfully completed the drilling
of 135 appraisal wells on our Pike oil sands lease. The results were consistent with
our expectations and will assist in determining the optimal development configuration.
We anticipate filing a regulatory application for the first phase of Pike in the first
half of 2012. |
|
|
|
Net production from the Barnett Shale exceeded 1.2 billion cubic feet of natural
gas equivalent per day in the first quarter, including 43,000 barrels per day of
liquids. This was an 11 percent increase over the first quarter of 2010. |
|
|
|
We brought six operated Granite Wash wells online in the first quarter. Initial
production from these wells averaged 1,760 barrels of oil-equivalent per day,
including 250 barrels of oil and 490 barrels of natural gas liquids per day. We have
an average working interest of 84 percent in these wells. |
22
Results of Operations
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change (1) |
|
Oil Volumes (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
3 |
|
|
|
3 |
|
|
|
+23 |
% |
Canada |
|
|
7 |
|
|
|
7 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
10 |
|
|
|
10 |
|
|
|
+8 |
% |
U.S. Offshore |
|
|
|
|
|
|
1 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
10 |
|
|
|
11 |
|
|
|
-4 |
% |
|
|
|
|
|
|
|
|
|
|
|
Gas Volumes (Bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
177 |
|
|
|
166 |
|
|
|
+7 |
% |
Canada |
|
|
51 |
|
|
|
50 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
228 |
|
|
|
216 |
|
|
|
+5 |
% |
U.S. Offshore |
|
|
|
|
|
|
10 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
228 |
|
|
|
226 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
NGLs Volumes (MMBbls) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
8 |
|
|
|
7 |
|
|
|
+16 |
% |
Canada |
|
|
1 |
|
|
|
1 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
9 |
|
|
|
8 |
|
|
|
+14 |
% |
U.S. Offshore |
|
|
|
|
|
|
|
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
9 |
|
|
|
8 |
|
|
|
+12 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total Volumes (MMBoe) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
|
41 |
|
|
|
37 |
|
|
|
+10 |
% |
Canada |
|
|
16 |
|
|
|
16 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
57 |
|
|
|
53 |
|
|
|
+7 |
% |
U.S. Offshore |
|
|
|
|
|
|
3 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
57 |
|
|
|
56 |
|
|
|
+1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 (1) |
|
|
2010 (1) |
|
|
Change |
|
Oil Prices (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
88.73 |
|
|
$ |
74.81 |
|
|
|
+19 |
% |
Canada |
|
$ |
60.86 |
|
|
$ |
62.50 |
|
|
|
-3 |
% |
North America Onshore |
|
$ |
70.95 |
|
|
$ |
66.41 |
|
|
|
+7 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
76.99 |
|
|
|
N/M |
|
Total |
|
$ |
70.95 |
|
|
$ |
67.58 |
|
|
|
+5 |
% |
Gas Prices (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
3.50 |
|
|
$ |
4.66 |
|
|
|
-25 |
% |
Canada |
|
$ |
4.03 |
|
|
$ |
5.08 |
|
|
|
-21 |
% |
North America Onshore |
|
$ |
3.62 |
|
|
$ |
4.76 |
|
|
|
-24 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
5.63 |
|
|
|
N/M |
|
Total |
|
$ |
3.62 |
|
|
$ |
4.80 |
|
|
|
-25 |
% |
NGLs Prices (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
35.41 |
|
|
$ |
34.22 |
|
|
|
+3 |
% |
Canada |
|
$ |
54.18 |
|
|
$ |
48.95 |
|
|
|
+11 |
% |
North America Onshore |
|
$ |
37.39 |
|
|
$ |
35.98 |
|
|
|
+4 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
40.59 |
|
|
|
N/M |
|
Total |
|
$ |
37.39 |
|
|
$ |
36.09 |
|
|
|
+4 |
% |
Combined Prices (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
29.77 |
|
|
$ |
32.81 |
|
|
|
-9 |
% |
Canada |
|
$ |
40.78 |
|
|
$ |
44.50 |
|
|
|
-8 |
% |
North America Onshore |
|
$ |
32.86 |
|
|
$ |
36.29 |
|
|
|
-9 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
51.07 |
|
|
|
N/M |
|
Total |
|
$ |
32.86 |
|
|
$ |
37.07 |
|
|
|
-11 |
% |
|
|
|
(1) |
|
The prices presented exclude any effects due to oil, gas and NGL derivatives. |
23
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, 2011 and 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(In millions) |
|
2010 sales |
|
$ |
710 |
|
|
$ |
1,086 |
|
|
$ |
274 |
|
|
$ |
2,070 |
|
Changes due to volumes |
|
|
(25 |
) |
|
|
7 |
|
|
|
32 |
|
|
|
14 |
|
Changes due to prices |
|
|
34 |
|
|
|
(269 |
) |
|
|
11 |
|
|
|
(224 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
2011 sales |
|
$ |
719 |
|
|
$ |
824 |
|
|
$ |
317 |
|
|
$ |
1,860 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales
Oil sales decreased $25 million in the first three months of 2011 due to a 4 percent decrease
in production. The decrease was primarily due to the divestiture of our U.S. Offshore properties in
the second quarter of 2010, partially offset by an 8 percent increase in our North America Onshore
production. The increased North America Onshore production resulted primarily from continued
development of our Permian Basin properties and our Jackfish thermal heavy oil project in Canada.
Oil sales increased $34 million in the first three months of 2011 as a result of a 5 percent
increase in our realized price without hedges. The largest contributor to the increase in our
realized price was the increase in the average NYMEX West Texas Intermediate index price over the
same time period. This was partially offset by an increase in our price differential based upon the
NYMEX index. The larger differential resulted primarily from the widening of the heavy oil
differentials related to our Canadian operations.
Gas Sales
A 1 percent increase in production during the first quarter of 2011 caused gas sales to
increase by $7 million. The increase was comprised of the net effect of a 5 percent increase in our
North America Onshore production, partially offset by the divestiture of our U.S. Offshore
properties in the second quarter of 2010. The increased North America Onshore production resulted
primarily from continued development activities in the Barnett and Cana-Woodford Shales, partially
offset by natural declines in our other operating areas.
Gas sales decreased $269 million during the first three months of 2011 as a result of a 25
percent decrease in our realized price without hedges. This decrease was largely due to decreases
in the North American regional index prices upon which our gas sales are based.
NGL Sales
NGL sales increased $32 million in the first quarter of 2011 due to a 12 percent increase in
production. The increase in production was primarily due to increased drilling in North America
Onshore areas that have liquids-rich gas.
NGL sales increased $11 million during the first three months of 2011 as a result of a 4
percent increase in our realized price without hedges. This increase was largely due to an increase
in the Mont Belvieu, Texas index price over the same time period.
Oil, Gas and NGL Derivatives
The following tables provide financial information associated with our oil, gas and NGL
hedges. The first table presents the cash settlements and unrealized gains and losses recognized as
components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and
without, the effects of the cash settlements. The prices do not include the effects of unrealized
gains and losses.
24
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Cash settlement receipts (payments): |
|
|
|
|
|
|
|
|
Gas derivatives |
|
$ |
91 |
|
|
$ |
96 |
|
Oil derivatives |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total cash settlements |
|
|
86 |
|
|
|
96 |
|
|
|
|
|
|
|
|
Unrealized (losses) gains on fair value changes: |
|
|
|
|
|
|
|
|
Gas derivatives |
|
|
(57 |
) |
|
|
520 |
|
Oil derivatives |
|
|
(198 |
) |
|
|
4 |
|
NGL derivatives |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized (losses) gains on fair value changes |
|
|
(254 |
) |
|
|
524 |
|
|
|
|
|
|
|
|
Oil, gas and NGL derivatives |
|
$ |
(168 |
) |
|
$ |
620 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2011 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
70.95 |
|
|
$ |
3.62 |
|
|
$ |
37.39 |
|
|
$ |
32.86 |
|
Cash settlements of hedges |
|
|
(0.48 |
) |
|
|
0.39 |
|
|
|
0.06 |
|
|
|
1.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
70.47 |
|
|
$ |
4.01 |
|
|
$ |
37.45 |
|
|
$ |
34.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2010 |
|
|
|
Oil |
|
|
Gas |
|
|
NGLs |
|
|
Total |
|
|
|
(Per Bbl) |
|
|
(Per Mcf) |
|
|
(Per Bbl) |
|
|
(Per Boe) |
|
Realized price without hedges |
|
$ |
67.58 |
|
|
$ |
4.80 |
|
|
$ |
36.09 |
|
|
$ |
37.07 |
|
Cash settlements of hedges |
|
|
|
|
|
|
0.42 |
|
|
|
|
|
|
|
1.71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, including cash settlements |
|
$ |
67.58 |
|
|
$ |
5.22 |
|
|
$ |
36.09 |
|
|
$ |
38.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our oil, gas and NGL derivatives include price swaps, costless collars and basis swaps. For
the price swaps, we receive a fixed price for our production and pay a variable market price to the
contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly
price indices are outside of the ranges set by the floor and ceiling prices in the various collars,
we cash-settle the difference with the counterparty to the collars. For the basis swaps, we receive
a fixed differential between two regional gas index prices and pay a variable differential on the
same two index prices to the contract counterparty. Cash settlements as presented in the tables
above represent realized gains or losses related to these various instruments.
Additionally, to enhance a portion of our natural gas price swaps, we have sold gas call
options for 2012 and oil call options for 2011 and 2012. The call options give counterparties the
right to purchase production at a predetermined price.
During the first three months of 2011, we received $91 million, or $0.39 per Mcf, from
counterparties to settle our gas derivatives and paid $5 million, or $0.48 per Bbl, to
counterparties to settle our oil derivatives. During the first three months of 2010, we received
$96 million, or $0.42 per Mcf, from counterparties to settle our gas derivatives.
In addition to recognizing these cash settlement effects, we also recognize unrealized changes
in the fair values of our oil, gas and NGL derivative instruments in each reporting period. We
estimate the fair values of these derivatives primarily by using internal discounted cash flow
calculations. We periodically validate our valuation techniques by comparing our internally
generated fair value estimates with those obtained from contract counterparties or brokers.
The most significant variable to our cash flow calculations is our estimate of future
commodity prices. We base our estimate of future prices upon published forward commodity price
curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas
Intermediate forward curve for oil instruments. Based on the amount of volumes subject to our gas
derivative financial instruments at March 31, 2011, a 10 percent increase in these forward curves
would have increased our unrealized losses by approximately $163 million. A 10 percent increase in
the forward curves associated with our oil derivatives would have increased our unrealized losses
by approximately $302 million. Another key input to our cash flow calculations is our estimate of
volatility for these forward curves, which we base primarily upon
25
implied volatility. Finally, the amount of production subject to oil, gas and NGL derivatives
is not a variable in our cash flow calculations, but it does impact the total derivative value.
Counterparty credit risk is also a component of commodity derivative valuations. We have
mitigated our exposure to any single counterparty by contracting with fourteen counterparties.
Additionally, our derivative contracts generally require cash collateral to be posted if either our
or the counterpartys credit rating falls below investment grade. The mark-to-market exposure
threshold, above which collateral must be posted, decreases as the debt rating falls further below
investment grade. Such thresholds generally range from zero to $50 million for the majority of our
contracts. As of March 31, 2011, the credit ratings of all our counterparties were investment
grade.
Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred a
net loss of $168 million during the first three months of 2011 and generated a net gain of $620
million during the first three months of 2010. In addition to the impact of cash settlements, these
net gains and losses were impacted by new positions and settlements that occurred during each
period, as well as the relationships between contract prices and the associated forward curves. A
summary of our outstanding oil, gas and NGL derivative positions as of March 31, 2011 is included
in Item 3. Quantitative and Qualitative Disclosures About Market Risk of this report.
Marketing and Midstream Revenues and Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
|
|
|
|
Marketing and midstream: |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
455 |
|
|
$ |
530 |
|
|
|
-14 |
% |
Operating costs and expenses |
|
|
333 |
|
|
|
397 |
|
|
|
-16 |
% |
|
|
|
|
|
|
|
|
|
|
|
Operating profit |
|
$ |
122 |
|
|
$ |
133 |
|
|
|
-9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
Marketing and midstream revenues decreased $75 million and operating costs and expenses
decreased $64 million, causing operating profit to decrease $11 million. These decreases were
primarily due to lower natural gas prices, partially offset by increased natural gas throughput.
Lease Operating Expenses (LOE)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
Lease operating expenses ($ in millions): |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
208 |
|
|
$ |
191 |
|
|
|
+9 |
% |
Canada |
|
|
216 |
|
|
|
190 |
|
|
|
+13 |
% |
|
|
|
|
|
|
|
|
|
|
|
North America Onshore |
|
|
424 |
|
|
|
381 |
|
|
|
+11 |
% |
U.S. Offshore |
|
|
|
|
|
|
33 |
|
|
|
-100 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
424 |
|
|
$ |
414 |
|
|
|
+2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expenses per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Onshore |
|
$ |
5.11 |
|
|
$ |
5.12 |
|
|
|
-0 |
% |
Canada |
|
$ |
13.55 |
|
|
$ |
12.09 |
|
|
|
+12 |
% |
North America Onshore |
|
$ |
7.48 |
|
|
$ |
7.19 |
|
|
|
+4 |
% |
U.S. Offshore |
|
$ |
|
|
|
$ |
11.18 |
|
|
|
N/M |
|
Total |
|
$ |
7.48 |
|
|
$ |
7.41 |
|
|
|
+1 |
% |
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
LOE increased $10 million in the first three months of 2011. This amount consisted of a $43
million increase related to our North America Onshore operations and a $33 million decrease related
to our U.S. Offshore operations that were sold in the second quarter of 2010. Our 7 percent
increase in North America Onshore production increased LOE by $27 million. Additionally, North
America Onshore LOE increased $12 million due to changes in the exchange rate between the U.S. and
Canadian dollars. The higher exchange rate was also the main contributor to the increases in North
America Onshore and total LOE per Boe.
26
Taxes Other Than Income Taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
|
|
|
|
Production |
|
$ |
56 |
|
|
$ |
59 |
|
|
|
-5 |
% |
Ad valorem |
|
|
50 |
|
|
|
40 |
|
|
|
+26 |
% |
Other |
|
|
2 |
|
|
|
2 |
|
|
|
+34 |
% |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
108 |
|
|
$ |
101 |
|
|
|
+8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
Production taxes decreased $3 million due to a slight decrease in our U.S. Onshore revenues.
Ad valorem taxes increased $10 million due to higher estimated assessed values of our oil and gas
property and equipment.
Depreciation, Depletion and Amortization of Oil and Gas Properties (DD&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
Total production volumes (MMBoe) |
|
|
57 |
|
|
|
56 |
|
|
|
+1 |
% |
DD&A rate ($ per Boe) |
|
$ |
7.80 |
|
|
$ |
7.63 |
|
|
|
+2 |
% |
|
|
|
|
|
|
|
|
|
|
|
DD&A expense ($ in millions) |
|
$ |
442 |
|
|
$ |
426 |
|
|
|
+4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
The following table details the changes in DD&A of oil and gas properties between the three
months ended March 31, 2011 and 2010 (in millions).
|
|
|
|
|
2010 DD&A |
|
$ |
426 |
|
Change due to rate |
|
|
10 |
|
Change due to volumes |
|
|
6 |
|
|
|
|
|
2011 DD&A |
|
$ |
442 |
|
|
|
|
|
Oil and gas property-related DD&A increased $10 million during the first three months of 2011
due to a 2 percent increase in the DD&A rate. The largest contributors to the higher rate were our
drilling and development activities subsequent to the end of the first quarter of 2010 and changes
in the exchange rate between the U.S. and Canadian dollars. These increases were largely offset by
a decrease in the rate due to our 2010 U.S. offshore property divestitures.
General and Administrative Expenses (G&A)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
Change(1) |
|
|
|
($ in millions) |
|
|
|
|
|
Gross G&A |
|
$ |
238 |
|
|
$ |
245 |
|
|
|
-3 |
% |
Capitalized G&A |
|
|
(81 |
) |
|
|
(80 |
) |
|
|
+1 |
% |
Reimbursed G&A |
|
|
(27 |
) |
|
|
(27 |
) |
|
|
0 |
% |
|
|
|
|
|
|
|
|
|
|
|
Net G&A |
|
$ |
130 |
|
|
$ |
138 |
|
|
|
-6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All percentage changes included in this table are based on actual figures rather than the
rounded figures presented. |
Gross and net G&A decreased primarily due to lower employee compensation and benefits
resulting from our 2010 offshore divestitures.
27
Interest Expense
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Interest based on debt outstanding |
|
$ |
98 |
|
|
$ |
105 |
|
Capitalized interest |
|
|
(20 |
) |
|
|
(21 |
) |
Other |
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
|
Total interest expense |
|
$ |
81 |
|
|
$ |
86 |
|
|
|
|
|
|
|
|
Interest based on debt outstanding decreased primarily due to the early redemption of our 7.25
percent $350 million senior notes in the second quarter of 2010.
Interest-Rate and Other Financial Instruments
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
(Gains) losses from interest rate swaps: |
|
|
|
|
|
|
|
|
Cash settlements |
|
$ |
(16 |
) |
|
$ |
(16 |
) |
Unrealized fair value changes |
|
|
(1 |
) |
|
|
1 |
|
|
|
|
|
|
|
|
Total |
|
$ |
(17 |
) |
|
$ |
(15 |
) |
|
|
|
|
|
|
|
During the first three months of 2011 and 2010, we received cash settlements totaling $16
million from counterparties to settle our interest rate swaps.
In addition to recognizing cash settlements, we recognize unrealized changes in the fair
values of our interest rate swaps each reporting period. We estimate the fair values of our
interest rate swap financial instruments primarily by using internal discounted cash flow
calculations based upon forward interest-rate yields. We periodically validate our valuation
techniques by comparing our internally generated fair value estimates with those obtained from
contract counterparties or brokers. In the first three months of 2011, we recorded an unrealized
gain of $1 million as a result of changes in interest rates. In the first three months of 2010, we
recorded an unrealized loss of $1 million as a result of changes in interest rates.
The most significant variable to our cash flow calculations is our estimate of future interest
rate yields. We base our estimate of future yields upon our own internal model that utilizes
forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the
notional amount subject to the interest rate swaps at March 31, 2011, a 10% increase in these
forward curves would have increased our unrealized gain for our interest rate swaps by
approximately $69 million.
Similar to our commodity derivative contracts, counterparty credit risk is also a component of
interest rate derivative valuations. We have mitigated our exposure to any single counterparty by
contracting with seven separate counterparties. Additionally, our derivative contracts generally
require cash collateral to be posted if either our or the counterpartys credit rating falls below
investment grade. The mark-to-market exposure threshold, above which collateral must be posted,
decreases as the debt rating falls further below investment grade. Such thresholds generally range
from zero to $50 million for the majority of our contracts. The credit ratings of all our
counterparties were investment grade as of March 31, 2011.
28
Income Taxes
The following table presents our total income tax expense and a reconciliation of our
effective income tax rate to the U.S. statutory income tax rate.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
Total income tax expense (in millions) |
|
$ |
191 |
|
|
$ |
514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
|
35 |
% |
|
|
35 |
% |
State income taxes |
|
|
1 |
% |
|
|
1 |
% |
Taxation on Canadian operations |
|
|
(2 |
%) |
|
|
(1 |
%) |
Other |
|
|
(1 |
%) |
|
|
(3 |
%) |
|
|
|
|
|
|
|
Effective income tax expense rate |
|
|
33 |
% |
|
|
32 |
% |
|
|
|
|
|
|
|
Earnings From Discontinued Operations
The following table presents the components of our earnings from discontinued operations. The
decrease in earnings is primarily due to our 2010 asset divestitures.
|
|
|
|
|
|
|
|
|
|
|
Three Months |
|
|
|
Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
Total production (MMBoe) |
|
|
1 |
|
|
|
3 |
|
Combined price without hedges (per Boe) |
|
$ |
81.94 |
|
|
$ |
72.65 |
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Operating revenues |
|
$ |
43 |
|
|
$ |
212 |
|
|
|
|
|
|
|
|
Expenses and other, net: |
|
|
|
|
|
|
|
|
Operating expenses |
|
|
26 |
|
|
|
78 |
|
Restructuring costs |
|
|
6 |
|
|
|
|
|
Other, net |
|
|
(19 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
Total expenses and other, net |
|
|
13 |
|
|
|
75 |
|
|
|
|
|
|
|
|
Earnings before income taxes |
|
|
30 |
|
|
|
137 |
|
Income tax expense |
|
|
3 |
|
|
|
19 |
|
|
|
|
|
|
|
|
Earnings from discontinued operations |
|
$ |
27 |
|
|
$ |
118 |
|
|
|
|
|
|
|
|
29
Capital Resources, Uses and Liquidity
The following discussion of capital resources and liquidity should be read in conjunction with
the consolidated statements of cash flows included in Part I, Item 1.
Sources and Uses of Cash
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
Sources of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Operating cash flow continuing operations |
|
$ |
1,266 |
|
|
$ |
1,341 |
|
Commercial paper borrowings |
|
|
1,197 |
|
|
|
|
|
Stock option exercises |
|
|
88 |
|
|
|
8 |
|
Divestitures of property and equipment |
|
|
5 |
|
|
|
1,257 |
|
Other |
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
|
Total sources of cash and cash equivalents |
|
|
2,556 |
|
|
|
2,617 |
|
|
|
|
|
|
|
|
Uses of cash and cash equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(1,827 |
) |
|
|
(1,247 |
) |
Net purchases of short-term investments |
|
|
(1,491 |
) |
|
|
|
|
Repurchases of common stock |
|
|
(706 |
) |
|
|
|
|
Dividends |
|
|
(68 |
) |
|
|
(72 |
) |
Commercial paper repayments |
|
|
|
|
|
|
(1,192 |
) |
|
|
|
|
|
|
|
Total uses of cash and cash equivalents |
|
|
(4,092 |
) |
|
|
(2,511 |
) |
|
|
|
|
|
|
|
(Decrease) increase from continuing operations |
|
|
(1,536 |
) |
|
|
106 |
|
(Decrease) increase from discontinued operations, net of
distributions to continuing operations |
|
|
(58 |
) |
|
|
47 |
|
Effect of foreign exchange rates |
|
|
20 |
|
|
|
18 |
|
|
|
|
|
|
|
|
Net (decrease) increase in cash and cash equivalents |
|
$ |
(1,574 |
) |
|
$ |
171 |
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
1,716 |
|
|
$ |
1,182 |
|
|
|
|
|
|
|
|
Short-term investments at end of period |
|
$ |
1,636 |
|
|
$ |
|
|
|
|
|
|
|
|
|
Operating Cash Flow Continuing Operations
Net cash provided by operating activities (operating cash flow) continued to be a
significant source of capital and liquidity in the first three months of 2011. Changes in operating
cash flow are largely due to the same factors that affect our net earnings, with the exception of
those earnings changes due to noncash expenses such as DD&A, property impairments, financial
instrument fair value changes and deferred income taxes. As a result, our operating cash flow
decreased approximately 6 percent during 2011 primarily due to the decrease in revenues as
discussed in the Results of Operations section of this report.
During the first three months of 2011, our operating cash flow funded approximately 70 percent
of our cash payments for capital expenditures. Commercial paper borrowings were used to fund the
remainder of our cash-based capital expenditures. During the first three months of 2010, our
operating cash flow was sufficient to fund our cash payments for capital expenditures.
Other Sources of Cash Continuing and Discontinued Operations
As needed, we supplement our operating cash flow and available cash by accessing available
credit under our credit facilities and commercial paper program. We may also issue long-term debt
to supplement our operating cash flow while maintaining adequate liquidity under our credit
facilities. Additionally, we may acquire short-term investments to maximize our income on available
cash balances. As needed, we reduce such short-term investment balances to further supplement our
operating cash flow and available cash. Another source of cash proceeds comes from employee stock
option exercises.
During the first three months of 2011, we utilized commercial paper borrowings of $1.2 billion
to fund capital expenditures, common share repurchases and dividends in excess of our operating
cash flow.
30
During the first three months of 2011, we received proceeds of $88 million from shares issued
for employee stock option exercises.
During the first three months of 2010, we sold our interests in the Jack, St. Malo and Cascade
Lower Tertiary projects in the Gulf of Mexico for $1.3 billion and used the proceeds to repay
commercial paper borrowings.
Capital Expenditures
Our capital expenditures are presented by geographic area and type in the following table. The
amounts in the table reflect cash payments for capital expenditures, including cash paid for
capital expenditures incurred in prior quarters. Capital expenditures actually incurred during the
first three months of 2011 and 2010 were approximately $1.8 billion and $1.6 billion, respectively.
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, |
|
|
|
2011 |
|
|
2010 |
|
|
|
(In millions) |
|
U.S. Onshore |
|
$ |
1,114 |
|
|
$ |
627 |
|
Canada |
|
|
520 |
|
|
|
377 |
|
|
|
|
|
|
|
|
North America Onshore |
|
|
1,634 |
|
|
|
1,004 |
|
U.S. Offshore |
|
|
|
|
|
|
126 |
|
|
|
|
|
|
|
|
Total exploration and development |
|
|
1,634 |
|
|
|
1,130 |
|
Midstream |
|
|
72 |
|
|
|
48 |
|
Other |
|
|
121 |
|
|
|
69 |
|
|
|
|
|
|
|
|
Total continuing operations |
|
$ |
1,827 |
|
|
$ |
1,247 |
|
|
|
|
|
|
|
|
Our capital expenditures consist of amounts related to our oil and gas exploration and
development operations, our midstream operations and other corporate activities. The vast majority
of our capital expenditures are for the acquisition, drilling and development of oil and gas
properties, which totaled $1.6 billion and $1.1 billion in the first three months of 2011 and 2010,
respectively. The increase in exploration and development capital spending in the first three
months of 2011 was primarily due to increased drilling activities. With rising oil prices and
proceeds from our 2010 offshore divestitures, we are increasing drilling primarily to grow our
liquids production.
Capital expenditures for our midstream operations are primarily for the construction and
expansion of natural gas processing plants, natural gas pipeline systems and oil pipelines. Our
midstream capital expenditures are largely impacted by oil and gas drilling activities. Therefore,
the increase in development drilling also increased midstream capital activities.
Capital expenditures related to corporate activities increased in 2011. This increase is
largely driven by the construction of our new headquarters in Oklahoma City.
Short-term Investments
During the first three months of 2011, we purchased $1.6 billion of United States Treasury
bills that have original maturities greater than three months and are, therefore, considered
short-term investments. As of March 31, 2011, the average maturity of these short-term investments
was 121 days.
Repurchases of Common Stock
During the first three months of 2011, we continued repurchasing shares under our $3.5 billion
stock repurchase program announced in May 2010. Including unsettled shares, we repurchased 8.1
million common shares for $696 million, or $85.95 per share, in the first quarter of 2011. This
program expires on December 31, 2011.
Dividends
Our common stock dividends were $68 million and $72 million (quarterly rates of $0.16 per
share) in the first three months of 2011 and 2010, respectively.
In March 2011, we announced an increase of our quarterly cash dividend to $0.17 per share that
will begin in the second quarter of 2011.
31
Liquidity
Historically, our primary source of capital and liquidity has been 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 equity and debt securities that can be issued pursuant to our automatically
effective shelf registration statement filed with the SEC. Another significant source of future
liquidity will be proceeds from the sales of our remaining offshore assets in Brazil and Angola. We
estimate the combination of these sources of capital will be adequate to fund future capital
expenditures, share repurchases, debt repayments and other contractual commitments. The following
sections discuss changes to our liquidity subsequent to filing our 2010 Annual Report on Form 10-K.
Operating Cash Flow
We expect operating cash flow to continue to be our primary source of liquidity. Our operating
cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, gas and
NGLs produced. To mitigate some of the risk inherent in prices, we have utilized various price
swap, fixed-price physical delivery and price collar contracts to set minimum and maximum prices on
our 2011 production. As of March 31, 2011, approximately 34 percent of our 2011 gas production is
associated with financial price swaps, collars and fixed-price physicals. We also have basis swaps
associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36 percent
of our 2011 oil production is associated with financial price collars. We also have call options
that, if exercised, would relate to an additional 16 percent of our 2011 oil production.
Looking beyond 2011, we have also entered into contracts to manage the price risk relative to
our 2012 and 2013 oil, gas and NGL production. A summary of these contracts as of March 31, 2011,
is included in Item 3. Quantitative and Qualitative Disclosures about Market Risk of this report.
Credit Availability
In March 2011, our Board of Directors authorized an increase in our commercial paper program
from $2.2 billion to $5.0 billion.
As of April 25, 2011, we had $2.7 billion of available capacity under our syndicated,
unsecured Senior Credit Facility and $1.3 billion of commercial paper borrowings outstanding.
The Senior Credit Facility contains only one material financial covenant. This covenant
requires us to maintain a ratio of total funded debt to total capitalization, as defined in the
credit agreement, of no more than 65 percent. The credit agreement defines total funded debt as
funds received through the issuance of debt securities such as debentures, bonds, notes payable,
credit facility borrowings and short-term commercial paper borrowings. In addition, total funded
debt includes all obligations with respect to payments received in consideration for oil, gas and
NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our
outstanding letters of credit and trade payables. The credit agreement defines total capitalization
as the sum of funded debt and stockholders equity adjusted for noncash financial writedowns, such
as full cost ceiling impairments. As of March 31, 2011, we were in compliance with this covenant.
Our debt-to-capitalization ratio at March 31, 2011, as calculated pursuant to the terms of the
agreement, was 17.7 percent.
Although we ended the first quarter of 2011 with $3.4 billion of cash and short-term
investments, the vast majority of this amount consists of proceeds from our International offshore
divestitures. Based on our evaluation of future cash needs across our operations in the United
States and Canada, these proceeds remain outside of the United States. With these proceeds
remaining outside of the United States, we expect to continue to increase our commercial paper
borrowings in the United States to supplement our United States based operating cash flow to fund
our capital expenditure and common stock repurchase programs.
Common Stock Repurchase Program
As of April 25, 2011, we had repurchased $2.1 billion, or 28.3 million common shares at an
average price of $72.98 under our $3.5 billion repurchase program. This program expires on December
31, 2011.
32
Pension Funding and Estimates
We previously disclosed that we expected to contribute approximately $84 million to our
qualified pension plans during 2011. We now expect to contribute $346 million to our qualified
pension plans in 2011, including $32 million that was contributed in the first quarter.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have commodity derivatives that pertain to production for the last nine months of 2011, as
well as 2012 and 2013. The key terms to all our oil, gas and NGL derivative financial instruments
as of March 31, 2011 are presented in the following tables.
We had the following open oil derivative positions:
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
Period |
|
Price Swaps |
|
|
Price Collars |
|
|
Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
|
Volume |
|
|
Average Floor Price |
|
|
Average Ceiling Price |
|
|
Volume |
|
|
Average Price |
|
Period |
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
|
($/Bbl) |
|
|
(Bbls/d) |
|
|
($/Bbl) |
Q2-Q4 2011 |
|
|
|
|
|
|
|
|
|
|
45,000 |
|
|
$ |
75.00 |
|
|
$ |
108.89 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
Q1-Q4 2012
|
|
|
9,000 |
|
|
$ |
104.20 |
|
|
|
35,000 |
|
|
$ |
82.14 |
|
|
$ |
126.42 |
|
|
|
19,500 |
|
|
$ |
95.00 |
|
We had the following open natural gas derivative positions:
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|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
Period |
|
Price Swaps |
|
|
Price Collars |
|
|
Call Options Sold |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
Volume |
|
|
Average Price |
|
|
Volume |
|
|
Average Floor Price |
|
|
Average Ceiling Price |
|
|
Volume |
|
|
Average Price |
|
Period |
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
|
($/MMBtu) |
|
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Q2 2011 |
|
|
912,500 |
|
|
$ |
5.24 |
|
|
|
350,000 |
|
|
$ |
4.18 |
|
|
$ |
4.68 |
|
|
|
|
|
|
|
|
|
Q3 2011 |
|
|
712,500 |
|
|
$ |
5.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q4 2011 |
|
|
712,500 |
|
|
$ |
5.51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1-Q4 2012 |
|
|
130,000 |
|
|
$ |
5.06 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
487,500 |
|
|
$ |
6.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
|
|
|
|
Differential to |
|
|
|
|
|
|
|
Volume |
|
|
Henry Hub |
|
Production Period |
|
Index |
|
(MMBtu/d) |
|
|
($/MMBtu) |
|
Q2-Q4 2011 |
|
Panhandle Eastern Pipeline |
|
|
150,000 |
|
|
$ |
0.33 |
|
33
We had the following open NGL derivative positions:
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|
|
|
|
|
|
|
|
|
Basis Swaps |
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
Volume |
|
|
Differential to WTI |
|
Production Period |
|
Pay |
|
|
(Bbls/d) |
|
|
($/Bbl) |
|
Q2-Q4 2011 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
9.75 |
|
Q1-Q4 2012 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
10.10 |
|
Q1-Q4 2013 |
|
Natural Gasoline |
|
|
500 |
|
|
$ |
6.80 |
|
The fair values of our commodity derivatives presented in the tables above are largely
determined by estimates of the forward curves of the relevant price indices. At March 31, 2011, a
10 percent increase in the forward curves associated with our gas derivative instruments would have
increased our unrealized losses by approximately $163 million. A 10 percent increase in the forward
curves associated with our oil derivative instruments would have increased our unrealized losses by
approximately $302 million.
Interest Rate Risk
At March 31, 2011, we had debt outstanding of $6.8 billion. Of this amount, $5.6 billion, or
82 percent bears fixed interest rates averaging 7.1 percent. Additionally, we had $1.2 billion of
outstanding commercial paper, bearing interest at floating rates which averaged 0.30 percent.
As of March 31, 2011, our interest rate swaps consisted of instruments with a total notional
amount of $2.1 billion. These consist of instruments with a notional amount of $1.15 billion in
which we receive a fixed rate and pay a variable rate. The remaining instruments consist of forward
starting swaps. Under the terms of the forward starting swaps, we will net settle these contracts
in September 2011, or sooner should we elect. The net settlement amount will be based upon us
paying a weighted-average fixed rate of 3.92 percent and receiving a floating rate that is based
upon the three-month LIBOR. The difference between the fixed and floating rate will be applied to
the notional amount for the 30-year period from September 30, 2011 to September 30, 2041. The key
terms of these contracts are presented in the following tables.
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|
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|
|
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|
|
|
Fixed-to-Floating Swaps |
|
|
|
Fixed Rate |
|
|
Variable |
|
|
|
|
Notional |
|
Received |
|
|
Rate Paid |
|
|
Expiration |
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
$300 |
|
|
4.30 |
% |
|
Six month LIBOR |
|
July 18, 2011 |
100 |
|
|
1.90 |
% |
|
Federal funds rate |
|
August 3, 2012 |
500 |
|
|
3.90 |
% |
|
Federal funds rate |
|
July 18, 2013 |
250 |
|
|
3.85 |
% |
|
Federal funds rate |
|
July 22, 2013 |
$1,150 |
|
|
3.82 |
% |
|
|
|
|
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|
|
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|
|
|
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|
|
|
|
|
|
Forward Starting Swaps |
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|
|
Fixed Rate |
|
|
Variable |
|
|
|
|
Notional |
|
Paid |
|
|
Rate Received |
|
|
Expiration |
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
$950 |
|
|
3.92 |
% |
|
Three month LIBOR |
|
September 30, 2011 |
The fair values of our interest rate instruments are largely determined by estimates of the
forward curves of the Federal Funds rate and LIBOR. At March 31, 2011, a 10 percent increase in
these forward curves would have increased our unrealized gain for our interest rate swaps by
approximately $69 million.
Foreign Currency Risk
Our net assets, net earnings and cash flows from our Canadian subsidiaries are based on the
U.S. dollar equivalent of such amounts measured in the Canadian dollar functional currency. Assets
and liabilities of the Canadian subsidiaries are translated to U.S. dollars using the applicable
exchange rate as of the end of a reporting period. Revenues, expenses and cash flow are translated
using the average exchange rate during the reporting period. A 10 percent unfavorable change in the
Canadian-to-U.S. dollar exchange rate would not materially impact our March 31, 2011 balance sheet.
34
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, 2011, to ensure
that the information required to be disclosed by Devon in the reports that it files or submits
under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within
the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
There was no change in Devons internal control over financial reporting during the first
quarter of 2011 that has materially affected, or is reasonably likely to materially affect, Devons
internal control over financial reporting.
PART II. Other Information
Item 1. Legal Proceedings
There have been no material changes to the information included in Item 3. Legal Proceedings
in our 2010 Annual Report on Form 10-K.
Item 1A. Risk Factors
There have been no material changes to the information included in Item 1A. Risk Factors in
our 2010 Annual Report on Form 10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum Dollar Value |
|
|
|
Total Number |
|
|
|
|
|
|
of Shares that May Yet |
|
|
|
of Shares |
|
|
Average Price |
|
|
Be Purchased Under the |
|
2011 Period |
|
Purchased(1) |
|
|
Paid per Share |
|
|
Plans or Programs(1) |
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
January 1 January 31 |
|
|
4,169,100 |
|
|
$ |
82.60 |
|
|
$ |
1,955 |
|
February 1 February 28 |
|
|
1,500,100 |
|
|
$ |
89.26 |
|
|
$ |
1,821 |
|
March 1 March 31 |
|
|
2,432,109 |
|
|
$ |
89.66 |
|
|
$ |
1,603 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
8,101,309 |
|
|
$ |
85.95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In May 2010, our Board of Directors approved a $3.5 billion share repurchase
program. This program expires December 31, 2011. As of March 31, 2011, we had repurchased
26.4 million common shares for $1.9 billion, or $71.83 per share under this program. |
Item 3. Defaults Upon Senior Securities
None.
Item 5. Other Information
None.
35
Item 6. Exhibits
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
|
|
|
Exhibit |
|
|
Number |
|
Description |
31.1
|
|
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2
|
|
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS
|
|
XBRL Instance Document |
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document |
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document |
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document |
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document |
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document |
36
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 4, 2011 |
/s/ Jeffrey A. Agosta
|
|
|
Jeffrey A. Agosta |
|
|
Executive Vice President Chief Financial Officer |
|
37
INDEX TO EXHIBITS
|
|
|
Exhibit |
|
|
Number |
|
Description |
31.1
|
|
Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2
|
|
Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1
|
|
Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.2
|
|
Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS
|
|
XBRL Instance Document |
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema Document |
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase Document |
|
|
|
101.LAB
|
|
XBRL Taxonomy Extension Labels Linkbase Document |
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase Document |
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase Document |
38