UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2014
or
¨ | 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)
Delaware | 73-1567067 | |
(State of other jurisdiction of incorporation or organization) |
(I.R.S. Employer identification No.) |
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333 West Sheridan Avenue, Oklahoma City, Oklahoma |
73102-5015 | |
(Address of principal executive offices) | (Zip code) |
Registrants telephone number, including area code: (405) 235-3611
Former name, 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 ¨
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 ¨
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.
Large accelerated filer | þ | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
On July 23, 2014, 409.1 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements as defined by the United States Securities and Exchange Commission (SEC). Such statements are those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 2013 reserve reports and other data in our possession or available from third parties. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Consequently, actual future results could differ materially from our expectations due to a number of factors, such as changes in the supply of and demand for oil, natural gas and natural gas liquids (NGLs) and related products and services; exploration or drilling programs; our ability to successfully complete mergers, acquisitions and divestitures; political or regulatory events; general economic and financial market conditions; and other risks and factors discussed in this report.
All subsequent written and oral forward-looking statements attributable to Devon Energy Corporation, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
2
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
Three Months | Six Months | |||||||||||||||
Ended June 30, | Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(Unaudited) | ||||||||||||||||
(In millions, except per share amounts) | ||||||||||||||||
Oil, gas and NGL sales |
$ | 2,679 | $ | 2,222 | $ | 5,236 | $ | 4,026 | ||||||||
Oil, gas and NGL derivatives |
(399 | ) | 366 | (719 | ) | 46 | ||||||||||
Marketing and midstream revenues |
2,230 | 500 | 3,718 | 987 | ||||||||||||
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Total operating revenues |
4,510 | 3,088 | 8,235 | 5,059 | ||||||||||||
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Lease operating expenses |
582 | 559 | 1,180 | 1,084 | ||||||||||||
Marketing and midstream operating expenses |
2,006 | 382 | 3,311 | 745 | ||||||||||||
General and administrative expenses |
189 | 167 | 400 | 317 | ||||||||||||
Production and property taxes |
150 | 125 | 287 | 238 | ||||||||||||
Depreciation, depletion and amortization |
828 | 674 | 1,567 | 1,378 | ||||||||||||
Asset impairments |
| 40 | | 1,953 | ||||||||||||
Restructuring costs |
5 | 8 | 42 | 46 | ||||||||||||
Gains and losses on asset sales |
(1,057 | ) | 1 | (1,072 | ) | | ||||||||||
Other operating items |
33 | 32 | 56 | 55 | ||||||||||||
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Total operating expenses |
2,736 | 1,988 | 5,771 | 5,816 | ||||||||||||
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Operating income (loss) |
1,774 | 1,100 | 2,464 | (757 | ) | |||||||||||
Net financing costs |
131 | 103 | 243 | 206 | ||||||||||||
Other nonoperating items |
89 | | 107 | 2 | ||||||||||||
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Earnings (loss) before income taxes |
1,554 | 997 | 2,114 | (965 | ) | |||||||||||
Income tax expense (benefit) |
854 | 314 | 1,085 | (309 | ) | |||||||||||
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Net earnings (loss) |
700 | 683 | 1,029 | (656 | ) | |||||||||||
Net earnings attributable to noncontrolling interests |
25 | | 30 | | ||||||||||||
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Net earnings (loss) attributable to Devon |
$ | 675 | $ | 683 | $ | 999 | $ | (656 | ) | |||||||
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Net earnings (loss) per share attributable to Devon: |
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Basic |
$ | 1.65 | $ | 1.69 | $ | 2.45 | $ | (1.63 | ) | |||||||
Diluted |
$ | 1.64 | $ | 1.68 | $ | 2.44 | $ | (1.63 | ) | |||||||
Comprehensive earnings (loss): |
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Net earnings (loss) |
$ | 700 | $ | 683 | $ | 1,029 | $ | (656 | ) | |||||||
Other comprehensive earnings (loss), net of tax: |
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Foreign currency translation |
292 | (271 | ) | (6 | ) | (454 | ) | |||||||||
Pension and postretirement plans |
5 | 5 | 8 | 9 | ||||||||||||
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Other comprehensive earnings (loss), net of tax |
297 | (266 | ) | 2 | (445 | ) | ||||||||||
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Comprehensive earnings (loss) |
997 | 417 | 1,031 | (1,101 | ) | |||||||||||
Comprehensive earnings attributable to noncontrolling interests |
25 | | 30 | | ||||||||||||
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Comprehensive earnings (loss) attributable to Devon |
$ | 972 | $ | 417 | $ | 1,001 | $ | (1,101 | ) | |||||||
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See accompanying notes to consolidated financial statements.
3
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months | ||||||||
Ended June 30, | ||||||||
2014 | 2013 | |||||||
(Unaudited) | ||||||||
(In millions) | ||||||||
Cash flows from operating activities: |
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Net earnings (loss) |
$ | 1,029 | $ | (656 | ) | |||
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
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Depreciation, depletion and amortization |
1,567 | 1,378 | ||||||
Gain on asset sales |
(1,072 | ) | | |||||
Asset impairments |
| 1,953 | ||||||
Deferred income tax expense (benefit) |
777 | (441 | ) | |||||
Derivatives and other financial instruments |
761 | (103 | ) | |||||
Cash settlements on derivatives and financial instruments |
(245 | ) | 149 | |||||
Other noncash charges |
229 | 176 | ||||||
Net change in working capital |
470 | (128 | ) | |||||
Change in long-term other assets |
(77 | ) | 22 | |||||
Change in long-term other liabilities |
20 | 48 | ||||||
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Net cash from operating activities |
3,459 | 2,398 | ||||||
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Cash flows from investing activities: |
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Acquisitions of property, equipment and businesses |
(6,224 | ) | | |||||
Capital expenditures |
(3,341 | ) | (3,569 | ) | ||||
Proceeds from property and equipment divestitures |
2,942 | 34 | ||||||
Purchases of short-term investments |
| (1,076 | ) | |||||
Redemptions of short-term investments |
| 2,550 | ||||||
Redemptions of long-term investments |
57 | | ||||||
Other |
84 | 82 | ||||||
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Net cash from investing activities |
(6,482 | ) | (1,979 | ) | ||||
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Cash flows from financing activities: |
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Proceeds from borrowings of long-term debt, net of issuance costs |
3,720 | | ||||||
Net short-term debt repayments |
(862 | ) | (1,495 | ) | ||||
Long-term debt repayments |
(3,990 | ) | | |||||
Proceeds from stock option exercises |
83 | 1 | ||||||
Proceeds from issuance of subsidiary units |
20 | | ||||||
Dividends paid on common stock |
(189 | ) | (170 | ) | ||||
Distributions to noncontrolling interests |
(141 | ) | | |||||
Other |
9 | 5 | ||||||
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Net cash from financing activities |
(1,350 | ) | (1,659 | ) | ||||
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Effect of exchange rate changes on cash |
13 | (34 | ) | |||||
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Net change in cash and cash equivalents |
(4,360 | ) | (1,274 | ) | ||||
Cash and cash equivalents at beginning of period |
6,066 | 4,637 | ||||||
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Cash and cash equivalents at end of period |
$ | 1,706 | $ | 3,363 | ||||
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See accompanying notes to consolidated financial statements.
4
DEVON ENERGY CORPORATION AND SUBSIDIARIES
June 30, | December 31, | |||||||
2014 | 2013 | |||||||
(Unaudited) | ||||||||
(In millions, except share data) | ||||||||
ASSETS | ||||||||
Current assets: |
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Cash and cash equivalents |
$ | 1,706 | $ | 6,066 | ||||
Accounts receivable |
2,301 | 1,520 | ||||||
Other current assets |
385 | 419 | ||||||
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Total current assets |
4,392 | 8,005 | ||||||
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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 |
75,242 | 73,995 | ||||||
Not subject to amortization |
3,984 | 2,791 | ||||||
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Total oil and gas |
79,226 | 76,786 | ||||||
Other |
8,956 | 6,195 | ||||||
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Total property and equipment, at cost |
88,182 | 82,981 | ||||||
Less accumulated depreciation, depletion and amortization |
(51,183 | ) | (54,534 | ) | ||||
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Property and equipment, net |
36,999 | 28,447 | ||||||
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Goodwill |
8,408 | 5,858 | ||||||
Other long-term assets |
1,316 | 567 | ||||||
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Total assets |
$ | 51,115 | $ | 42,877 | ||||
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
$ | 1,529 | $ | 1,229 | ||||
Revenues and royalties payable |
1,581 | 786 | ||||||
Short-term debt |
475 | 4,066 | ||||||
Other current liabilities |
1,094 | 574 | ||||||
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Total current liabilities |
4,679 | 6,655 | ||||||
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Long-term debt |
11,880 | 7,956 | ||||||
Asset retirement obligations |
1,541 | 2,140 | ||||||
Other long-term liabilities |
1,029 | 834 | ||||||
Deferred income taxes |
5,927 | 4,793 | ||||||
Stockholders equity: |
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Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 409 million and 406 million shares in 2014 and 2013, respectively |
41 | 41 | ||||||
Additional paid-in capital |
3,943 | 3,780 | ||||||
Retained earnings |
16,220 | 15,410 | ||||||
Accumulated other comprehensive earnings |
1,270 | 1,268 | ||||||
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Total stockholders equity attributable to Devon |
21,474 | 20,499 | ||||||
Noncontrolling interests |
4,585 | | ||||||
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Total stockholders equity |
26,059 | 20,499 | ||||||
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Commitments and contingencies (Note 17) |
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Total liabilities and stockholders equity |
$ | 51,115 | $ | 42,877 | ||||
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See accompanying notes to consolidated financial statements.
5
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Accumulated | ||||||||||||||||||||||||||||||||
Additional | Other | Total | ||||||||||||||||||||||||||||||
Common Stock | Paid-In | Retained | Comprehensive | Treasury | Noncontrolling | Stockholders | ||||||||||||||||||||||||||
Shares | Amount | Capital | Earnings | Earnings | Stock | Interests | Equity | |||||||||||||||||||||||||
(Unaudited) | ||||||||||||||||||||||||||||||||
(In millions) | ||||||||||||||||||||||||||||||||
Six Months Ended June 30, 2014 |
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Balance as of December 31, 2013 |
406 | $ | 41 | $ | 3,780 | $ | 15,410 | $ | 1,268 | $ | | $ | | $ | 20,499 | |||||||||||||||||
Net earnings |
| | | 999 | | | 30 | 1,029 | ||||||||||||||||||||||||
Other comprehensive earnings, net of tax |
| | | | 2 | | | 2 | ||||||||||||||||||||||||
Stock option exercises |
1 | | 83 | | | | | 83 | ||||||||||||||||||||||||
Restricted stock grants, net of cancellations |
2 | | | | | | | | ||||||||||||||||||||||||
Common stock repurchased |
| | | | | (5 | ) | | (5 | ) | ||||||||||||||||||||||
Common stock retired |
| | (5 | ) | | | 5 | | | |||||||||||||||||||||||
Common stock dividends |
| | | (189 | ) | | | | (189 | ) | ||||||||||||||||||||||
Share-based compensation |
| | 84 | | | | | 84 | ||||||||||||||||||||||||
Share-based compensation tax benefits |
| | 1 | | | | | 1 | ||||||||||||||||||||||||
Subsidiary equity transactions |
| | | | | | 27 | 27 | ||||||||||||||||||||||||
Acquisition of noncontrolling interests |
| | | | | | 4,664 | 4,664 | ||||||||||||||||||||||||
Distributions to noncontrolling interests |
| | | | | | (141 | ) | (141 | ) | ||||||||||||||||||||||
Other |
| | | | | | 5 | 5 | ||||||||||||||||||||||||
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Balance as of June 30, 2014 |
409 | $ | 41 | $ | 3,943 | $ | 16,220 | $ | 1,270 | $ | | $ | 4,585 | $ | 26,059 | |||||||||||||||||
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Six Months Ended June 30, 2013 |
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Balance as of December 31, 2012 |
406 | $ | 41 | $ | 3,688 | $ | 15,778 | $ | 1,771 | $ | | $ | | $ | 21,278 | |||||||||||||||||
Net loss |
| | | (656 | ) | | | | (656 | ) | ||||||||||||||||||||||
Other comprehensive loss, net of tax |
| | | | (445 | ) | | | (445 | ) | ||||||||||||||||||||||
Stock option exercises |
| | 1 | | | | | 1 | ||||||||||||||||||||||||
Common stock repurchased |
| | | | | (9 | ) | | (9 | ) | ||||||||||||||||||||||
Common stock retired |
| | (9 | ) | | | 9 | | | |||||||||||||||||||||||
Common stock dividends |
| | | (170 | ) | | | | (170 | ) | ||||||||||||||||||||||
Share-based compensation |
| | 62 | | | | | 62 | ||||||||||||||||||||||||
Share-based compensation tax benefits |
| | 5 | | | | | 5 | ||||||||||||||||||||||||
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Balance as of June 30, 2013 |
406 | $ | 41 | $ | 3,747 | $ | 14,952 | $ | 1,326 | $ | | $ | | $ | 20,066 | |||||||||||||||||
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See accompanying notes to consolidated financial statements.
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. Summary of Significant Accounting Policies
The accompanying unaudited 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 (U.S.) have been omitted. The accompanying financial statements and notes should be read in conjunction with the financial statements and notes included in Devons 2013 Annual Report on Form 10-K.
The accompanying unaudited interim financial statements furnished in this report reflect all adjustments that are, in the opinion of management, necessary for a fair statement of Devons results of operations and cash flows for the three-month and six-month periods ended June 30, 2014 and 2013 and Devons financial position as of June 30, 2014.
Basis of Presentation
The accompanying consolidated financial statements include the accounts of Devon and entities in which it holds a controlling interest. All intercompany transactions have been eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant influence over operating and financial policies, are accounted for using the equity method. In applying the equity method of accounting, the investments are initially recognized at cost, and subsequently adjusted for Devons proportionate share of earnings, losses, and distributions. Investments accounted for using the equity method and cost method are reported as a component of other long-term assets.
As discussed more fully in Note 2, on March 7, 2014, Devon completed a business combination whereby Devon controls both EnLink Midstream Partners, LP (the Partnership) and its general partner entity, EnLink Midstream, LLC (EnLink). Devon controls both the Partnerships and EnLinks operations; therefore, the Partnerships and EnLinks accounts are included in Devons accompanying consolidated financial statements subsequent to the completion of the transaction. The portions of the Partnerships and EnLinks net earnings and stockholders equity not attributable to Devons controlling interest are shown separately as noncontrolling interests in the accompanying consolidated comprehensive statements of earnings and consolidated balance sheets.
Intangible Assets
EnLinks long-term assets include intangible assets, consisting of customer relationships. These assets are amortized on a straight-line basis over the expected periods of benefits, which range from ten to twenty years.
Recently Issued Accounting Standards Not Yet Adopted
In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606). The update provides guidance concerning the recognition and measurement of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. The update is effective for Devon beginning in calendar year 2017. Devon is evaluating the impact this standard will have on its consolidated financial statements and related disclosures.
2. Acquisitions and Divestitures
Formation of EnLink Midstream, LLC and EnLink Midstream Partners, LP
On March 7, 2014, Devon, Crosstex Energy, Inc. and Crosstex Energy, LP (together with Crosstex Energy, Inc., Crosstex) completed a business combination to combine substantially all of Devons U.S. midstream assets with Crosstexs assets to form a new midstream business. The new business consists of the Partnership and EnLink, a master limited partnership and a general partner entity, respectively, which are both publicly traded entities.
In exchange for a controlling interest in both EnLink and the Partnership, Devon contributed its equity interest in a newly formed Devon subsidiary, EnLink Midstream Holdings, LP (EnLink Holdings) and $100 million in cash. EnLink Holdings owns Devons midstream assets in the Barnett Shale in north Texas and the Cana and Arkoma Woodford Shales in Oklahoma, as well as Devons economic interest in Gulf Coast Fractionators in Mt. Belvieu, Texas. The Partnership and EnLink each own 50 percent of EnLink Holdings.
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The ownership of EnLink is approximately:
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70% - Devon |
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30% - Public unitholders |
The ownership of the Partnership is approximately:
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52% - Devon |
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41% - Public unitholders |
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7% - EnLink |
This business combination was accounted for using the acquisition method of accounting. Under the acquisition method of accounting, EnLink Holdings was the accounting acquirer because its parent company, Devon, obtained control of EnLink and the Partnership as a result of the business combination. Consequently, EnLink Holdings assets and liabilities retained their carrying values. Additionally, the Crosstex assets acquired and liabilities assumed by the Partnership and EnLink in the business combination, as well as EnLinks noncontrolling interest in the Partnership, were recorded at their fair values which were measured as of the acquisition date, March 7, 2014. The excess of the purchase price over the estimated fair values of Crosstexs net assets acquired was recorded as goodwill.
The following table summarizes the purchase price (in millions, except unit price).
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
(1) | The final purchase price is based on the fair value of Crosstex Energy Inc.s common shares as of the closing date, March 7, 2014. |
(2) | Represents the value of noncontrolling interests related to EnLinks equity investment in E2 Energy Services, LLC and E2 Appalachian Compression, LLC (collectively E2). |
(3) | The Partnership converted the preferred units to common units in February 2014. |
(4) | The final purchase price is based on the fair value of the Partnerships common shares as of the closing date, March 7, 2014. |
The preliminary allocation of the purchase price is as follows (in millions):
Assets acquired: |
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Current assets |
$ | 438 | ||
Property, plant and equipment, net |
2,438 | |||
Intangible assets |
546 | |||
Equity investment |
222 | |||
Goodwill (1) |
3,292 | |||
Other long term assets |
1 | |||
Liabilities assumed: |
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Current liabilities |
(515 | ) | ||
Long-term debt |
(1,454 | ) | ||
Deferred income taxes |
(203 | ) | ||
Other long-term liabilities |
(101 | ) | ||
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Total consideration and fair value of noncontrolling interests |
$ | 4,664 | ||
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(1) | Goodwill is the excess of the consideration transferred over the net assets recognized and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Goodwill is not amortized and is not deductible for tax purposes. |
GeoSouthern Energy Acquisition
On November 20, 2013, Devon entered into a Purchase and Sale Agreement with GeoSouthern Energy Corporation (GeoSouthern) and a wholly owned subsidiary of GeoSouthern to acquire GeoSoutherns interests in certain affiliates (the Acquired Companies) that own certain oil and gas properties, leasehold mineral interest and related assets located in the Eagle Ford Shale. On February 28, 2014, the GeoSouthern acquisition closed, and GeoSouthern transferred the Acquired Companies to Devon in exchange for the aggregate purchase price of approximately $6.0 billion. Devon funded the acquisition price with cash on hand and debt financing. In connection with the GeoSouthern acquisition, Devon acquired approximately 82,000 net acres located in DeWitt and Lavaca counties in south Texas. The transaction was accounted for using the acquisition method, which requires, among other things, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed in the transaction (in millions).
Cash and cash equivalents |
$ | 95 | ||
Other current assets |
256 | |||
Proved properties |
5,029 | |||
Unproved properties |
1,008 | |||
Midstream assets |
85 | |||
Current liabilities |
(437 | ) | ||
Long-term liabilities |
(6 | ) | ||
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Net assets acquired |
$ | 6,030 | ||
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9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
EnLink and GeoSouthern Operating Results
The following table presents EnLinks (acquired Crosstex assets and liabilities) and GeoSoutherns operating revenues and net earnings included in Devons consolidated statements of earnings subsequent to the transactions described above.
Three Months Ended
June 30, 2014 |
Six Months Ended
June 30, 2014 |
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GeoSouthern | EnLink | GeoSouthern | EnLink | |||||||||||||
(In millions) | (In millions) | |||||||||||||||
Total operating revenues |
$ | 586 | $ | 771 | $ | 740 | $ | 970 | ||||||||
Total operating expenses |
312 | 765 | 386 | 962 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Operating income |
$ | 274 | $ | 6 | $ | 354 | $ | 8 | ||||||||
|
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|
|
|
|
|
|
Pro Forma Financial Information
The following unaudited pro forma financial information has been prepared assuming both the EnLink formation and the GeoSouthern acquisition occurred on January 1, 2013. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination and acquisition had been completed at the dates indicated. In addition, they do not project Devons results of operations for any future period.
Six Months Ended
June 30, |
||||||||
2014 | 2013 | |||||||
(In millions) | ||||||||
Total operating revenues |
$ | 8,882 | $ | 6,211 | ||||
Net earnings (loss) |
$ | 1,043 | $ | (635 | ) | |||
Noncontrolling interests |
$ | 43 | $ | 28 | ||||
Net earnings (loss) attributable to Devon |
$ | 1,000 | $ | (663 | ) | |||
Net earnings (loss) per common share attributable to Devon |
$ | 2.45 | $ | (1.63 | ) |
Non-Core Asset Divestitures
In November 2013, Devon announced plans to divest certain non-core properties located throughout Canada and the U.S.
Canada
In the first quarter of 2014, Devon completed minor divestiture transactions for $142 million ($155 million Canadian dollars). In the second quarter of 2014, Devon sold conventional assets to Canadian Natural Resources Limited for $2.8 billion ($3.125 billion Canadian dollars).
Under full cost accounting rules, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost centers capitalized costs and proved reserves, then a gain or loss must be recognized. The Canadian divestitures significantly altered such relationship. Therefore, Devon recognized gains totaling $1.1 billion ($0.6 billion after-tax) during the first six months of 2014. These gains are included as a separate item in the accompanying consolidated comprehensive statements of earnings.
Included in the gain calculation noted above were asset retirement obligations of approximately $700 million assumed by the purchaser as well as the derecognition of approximately $700 million of goodwill allocated to the sold assets.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In conjunction with the divestitures noted above, Devon repatriated approximately $2.8 billion of proceeds to the U.S. in the second quarter of 2014. The proceeds were used to repay $0.7 billion of commercial paper and the $2.0 billion term loans that were drawn in the first quarter of 2014 to fund a portion of the GeoSouthern acquisition. Between collecting the divestiture proceeds and repatriating funds to the U.S., Devon recognized an $84 million foreign currency exchange loss and a $29 million foreign currency derivative loss. These losses are included in other nonoperating items in the accompanying consolidated comprehensive statements of earnings.
U.S.
On June 30, 2014, Devon reached an agreement to sell its U.S. non-core assets for $2.3 billion to Linn Energy. The transaction with Linn Energy is expected to close in the third quarter of 2014. No gain or loss is expected to be recognized on the U.S. non-core asset divestiture.
3. Derivative Financial Instruments
Objectives and Strategies
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production. These instruments are used to manage the inherent uncertainty of future revenues due to commodity price volatility and typically include financial price swaps, basis swaps, costless price collars and call options. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. Devon periodically enters into foreign exchange forward contracts to manage its exposure to fluctuations in exchange rates. Additionally, EnLink manages its exposure to fluctuations in commodity prices by hedging the impact of market fluctuations.
Devon does not intend to 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.
Counterparty Credit Risk
By using derivative financial instruments, Devon is exposed to credit 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 acceptable 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 contain provisions that provide for collateral payments, depending on levels of exposure and the credit rating of the counterparty. As of June 30, 2014, Devon did not hold any cash collateral from its counterparties.
Commodity Derivatives
As of June 30, 2014, Devon had the following open oil derivative positions. The first table presents Devons oil derivatives that settle against the average of the prompt month NYMEX West Texas Intermediate futures price. The second table presents Devons oil derivatives that settle against the Western Canadian Select index.
Price Swaps | Price Collars | Call Options Sold | ||||||||||||||||||||||||||
Period |
Volume
(Bbls/d) |
Weighted
Average Price ($/Bbl) |
Volume
(Bbls/d) |
Weighted
Average Floor Price ($/Bbl) |
Weighted
Average Ceiling Price ($/Bbl) |
Volume
(Bbls/d) |
Weighted
Average Price ($/Bbl) |
|||||||||||||||||||||
Q3-Q4 2014 |
75,000 | $ | 94.14 | 64,750 | $ | 89.33 | $ | 100.00 | 42,000 | $ | 116.43 | |||||||||||||||||
Q1-Q4 2015 |
100,492 | $ | 90.95 | 27,000 | $ | 89.14 | $ | 97.84 | 28,000 | $ | 116.43 | |||||||||||||||||
Q1-Q4 2016 |
| $ | | | $ | | $ | | 18,500 | $ | 103.11 |
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Basis Swaps | ||||||||||
Period |
Index |
Volume
(Bbls/d) |
Weighted Average
Differential to WTI ($/Bbl) |
|||||||
Q3 2014 |
Western Canadian Select | 30,000 | $ | (18.21 | ) |
As of June 30, 2014, Devon had the following open natural gas derivative positions. The first table presents Devons natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devons natural gas derivatives that settle against the AECO index.
Price Swaps | Price Collars | Call Options Sold | ||||||||||||||||||||||||||
Period |
Volume
(MMBtu/d) |
Weighted
Average Price ($/MMBtu) |
Volume
(MMBtu/d) |
Weighted
Average Floor Price ($/MMBtu) |
Weighted
Average Ceiling Price ($/MMBtu) |
Volume
(MMBtu/d) |
Weighted
Average Price ($/MMBtu) |
|||||||||||||||||||||
Q3-Q4 2014 |
800,000 | $ | 4.42 | 460,000 | $ | 4.03 | $ | 4.51 | 500,000 | $ | 5.00 | |||||||||||||||||
Q1-Q4 2015 |
210,000 | $ | 4.38 | 260,000 | $ | 4.05 | $ | 4.36 | 550,000 | $ | 5.09 | |||||||||||||||||
Q1-Q4 2016 |
| $ | | | $ | | $ | | 400,000 | $ | 5.00 |
Basis Swaps | ||||||||||||
Period |
Index |
Volume
(MMBtu/d) |
Weighted Average Differential
to Henry Hub ($/MMBtu) |
|||||||||
Q3-Q4 2014 |
AECO | 94,781 | $ | (0.52 | ) |
Interest Rate Derivatives
As of June 30, 2014, Devon had the following open interest rate derivative positions:
Notional |
Rate Received | Rate Paid | Expiration | |||||||||
(In millions) | ||||||||||||
$100 |
Three Month LIBOR | 0.92 | % | December 2016 | ||||||||
$100 |
1.76 | % | Three Month LIBOR | January 2019 |
Foreign Currency Derivatives
As of June 30, 2014, Devon had the following open foreign currency derivative positions:
Forward Contract |
||||||||||||||
Currency |
Contract
Type |
CAD
Notional |
Weighted Average
Fixed Rate Received |
Expiration | ||||||||||
(In millions) | (CAD-USD) | |||||||||||||
Canadian Dollar |
Sell | $ | 1,312 | 0.931 | September 2014 |
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Financial Statement Presentation
The following table presents the net gains and losses recognized in the accompanying comprehensive statements of earnings associated with derivative financial instruments. Net gains and losses associated with Devons commodity derivatives are presented in oil, gas and NGL derivatives in the accompanying comprehensive statements of earnings. Net gains and losses associated with EnLinks midstream commodity derivatives are presented in marketing and midstream revenues in the accompanying comprehensive statements of earnings. Net gains and losses associated with Devons interest rate and foreign currency derivatives are presented in other nonoperating items in the accompanying comprehensive statements of earnings.
Three Months
Ended June 30, |
Six Months
Ended June 30, |
|||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In millions) | ||||||||||||||||
Commodity derivatives |
$ | (399 | ) | $ | 366 | $ | (719 | ) | $ | 46 | ||||||
EnLink commodity derivatives |
(2 | ) | | (3 | ) | | ||||||||||
Interest rate derivatives |
1 | | 1 | | ||||||||||||
Foreign currency derivatives |
(54 | ) | 42 | (40 | ) | 57 | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net gains (losses) recognized in comprehensive statements of earnings |
$ | (454 | ) | $ | 408 | $ | (761 | ) | $ | 103 | ||||||
|
|
|
|
|
|
|
|
The following table presents the derivative fair values included in the accompanying balance sheets.
Balance Sheet Caption |
June 30,
2014 |
December 31,
2013 |
||||||||
(In millions) | ||||||||||
Asset derivatives: |
||||||||||
Commodity derivatives |
Other current assets | $ | 6 | $ | 75 | |||||
Commodity derivatives |
Other long-term assets | 11 | 28 | |||||||
Interest rate derivatives |
Other current assets | 1 | | |||||||
|
|
|
|
|||||||
Total asset derivatives |
$ | 18 | $ | 103 | ||||||
|
|
|
|
|||||||
Liability derivatives: |
||||||||||
Commodity derivatives |
Other current liabilities | $ | 386 | $ | 58 | |||||
Commodity derivatives |
Other long-term liabilities | 157 | 62 | |||||||
EnLink commodity derivatives |
Other current liabilities | 1 | | |||||||
EnLink commodity derivatives |
Other long-term liabilities | 1 | | |||||||
Foreign currency derivatives |
Other current liabilities | 5 | 1 | |||||||
|
|
|
|
|||||||
Total liability derivatives |
$ | 550 | $ | 121 | ||||||
|
|
|
|
4. Share-Based Compensation
The following table presents the effects of share-based compensation included in Devons accompanying comprehensive statements of earnings. Devons gross general and administrative expense for the first six months of 2014 includes $6 million of unit-based compensation related to grants made under EnLinks long-term incentive plans. The vesting for certain share-based awards was accelerated in the first quarter of 2014 in conjunction with the divestiture of Devons Canadian conventional assets. The associated expense for these accelerated awards is included in restructuring costs in the accompanying comprehensive statements of earnings. See Note 6 for further details.
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Six Months
Ended June 30, |
||||||||
2014 | 2013 | |||||||
(In millions) | ||||||||
Gross general and administrative expense |
$ | 106 | $ | 79 | ||||
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties |
$ | 27 | $ | 30 | ||||
Related income tax benefit |
$ | 13 | $ | 12 |
Under its 2009 Long-Term Incentive Plan, as amended, Devon granted share-based awards to certain employees in the first six months of 2014. The following sections include information related to these awards.
Restricted Stock Awards and Units
The following table presents a summary of Devons unvested restricted stock awards and units.
Restricted Stock
Award & Units |
Weighted Average
Grant-Date Fair Value |
|||||||
(In thousands) | ||||||||
Unvested at December 31, 2013 |
3,292 | $ | 59.76 | |||||
Granted |
3,343 | $ | 63.18 | |||||
Vested |
(505 | ) | $ | 60.87 | ||||
Forfeited |
(521 | ) | $ | 60.62 | ||||
|
|
|||||||
Unvested at June 30, 2014 |
5,609 | $ | 61.50 | |||||
|
|
As of June 30, 2014, Devons unrecognized compensation cost related to unvested restricted stock awards and units was $255 million. Such cost is expected to be recognized over a weighted-average period of 2.6 years.
Performance Based Restricted Stock Awards
The following table presents a summary of Devons performance based restricted stock awards.
Performance
Restricted Stock Awards |
Weighted Average
Grant-Date Fair Value |
|||||||
(In thousands) | ||||||||
Unvested at December 31, 2013 |
316 | $ | 56.25 | |||||
Granted |
234 | $ | 61.33 | |||||
Vested |
(75 | ) | $ | 53.45 | ||||
|
|
|||||||
Unvested at June 30, 2014 |
475 | $ | 59.20 | |||||
|
|
As of June 30, 2014, Devons unrecognized compensation cost related to these awards was $10 million. Such cost is expected to be recognized over a weighted-average period of 1.7 years.
Performance Share Units
The following table presents a summary of the grant-date fair values of performance share units granted in 2014 and the related assumptions.
2014 | ||||||||||||
Grant-date fair value |
$ | 70.18 | | $ | 81.05 | |||||||
Risk-free interest rate |
0.54 | % | ||||||||||
Volatility factor |
28.8 | % | ||||||||||
Contractual term (in years) |
2.89 |
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The following table presents a summary of Devons performance share units.
Performance Share
Units |
Weighted Average
Grant-Date Fair Value |
|||||||
(In thousands) | ||||||||
Unvested at December 31, 2013 |
925 | $ | 66.64 | |||||
Granted |
708 | $ | 77.77 | |||||
Forfeited |
(137 | ) | $ | 79.74 | ||||
|
|
|||||||
Unvested at June 30, 2014 (1) |
1,496 | $ | 70.90 | |||||
|
|
(1) | A maximum of 3.0 million common shares could be awarded based upon Devons final total shareholder return ranking. |
As of June 30, 2014, Devons unrecognized compensation cost related to unvested units was $48 million. Such cost is expected to be recognized over a weighted-average period of 1.8 years.
5. Asset Impairments
In the first six months of 2013, Devon recognized asset impairments related to its oil and gas property and equipment as presented below.
Six Months Ended
June 30, 2013 |
||||||||
Gross | Net of Taxes | |||||||
(In millions) | ||||||||
U.S. oil and gas assets |
$ | 1,110 | $ | 707 | ||||
Canada oil and gas assets |
843 | 632 | ||||||
|
|
|
|
|||||
Total asset impairments |
$ | 1,953 | $ | 1,339 | ||||
|
|
|
|
Oil and Gas Impairments
Under the full-cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full-cost ceiling at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum, net of related tax effects. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months.
The oil and gas impairments resulted primarily from declines in the U.S. and Canada full-cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which reduced proved reserve values.
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
6. Restructuring Costs
Canadian Divestitures
In the first six months of 2014, Devon recognized $42 million of employee related costs associated with its Canadian non-core asset divestitures. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are non-cash charges.
Office Consolidation
In October 2012, Devon announced plans to consolidate its U.S. personnel into a single operations group centrally located at the companys headquarters in Oklahoma City. As of December 31, 2013, Devon had completed this initiative and incurred $134 million of restructuring costs associated with the office consolidation.
Financial Statement Presentation
The schedule below summarizes restructuring costs presented in the accompanying comprehensive statements of earnings related to the Canadian divestitures and office consolidation.
Three Months
Ended June 30, |
Six Months
Ended June 30, |
|||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In millions) | ||||||||||||||||
Canada divestitures: |
||||||||||||||||
Employee related costs |
$ | 5 | $ | | $ | 42 | $ | | ||||||||
Office consolidation: |
||||||||||||||||
Lease obligations and other |
| 8 | | 46 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Restructuring costs |
$ | 5 | $ | 8 | $ | 42 | $ | 46 | ||||||||
|
|
|
|
|
|
|
|
The schedule below summarizes Devons restructuring liabilities.
Other
Current Liabilities |
Other
Long-Term Liabilities |
Total | ||||||||||
(In millions) | ||||||||||||
Balance as of December 31, 2013 |
$ | 27 | $ | 18 | $ | 45 | ||||||
Changes due to Canadian divestitures |
5 | 2 | 7 | |||||||||
Changes due to office consolidation |
(20 | ) | (1 | ) | (21 | ) | ||||||
Changes due to offshore divestiture |
(1 | ) | (1 | ) | (2 | ) | ||||||
|
|
|
|
|
|
|||||||
Balance as June 30, 2014 |
$ | 11 | $ | 18 | $ | 29 | ||||||
|
|
|
|
|
|
|||||||
Balance as of December 31, 2012 |
$ | 52 | $ | 9 | $ | 61 | ||||||
Changes due to office consolidation |
(7 | ) | 11 | 4 | ||||||||
Changes due to offshore divestiture |
(1 | ) | (1 | ) | (2 | ) | ||||||
|
|
|
|
|
|
|||||||
Balance as of June 30, 2013 |
$ | 44 | $ | 19 | $ | 63 | ||||||
|
|
|
|
|
|
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
7. Income Taxes
The following table presents Devons total income tax expense (benefit) and a reconciliation of its effective income tax rate to the U.S. statutory income tax rate.
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Total income tax expense (benefit) (in millions) |
$ | 854 | $ | 314 | $ | 1,085 | $ | (309 | ) | |||||||
|
|
|
|
|
|
|
|
|||||||||
U.S. statutory income tax rate |
35 | % | 35 | % | 35 | % | (35 | %) | ||||||||
Repatriations |
16 | % | | 12 | % | | ||||||||||
State income taxes |
| 1 | % | 1 | % | (1 | %) | |||||||||
Taxation on Canadian operations |
4 | % | (2 | %) | 2 | % | 6 | % | ||||||||
Taxes on EnLink formation |
| | 2 | % | | |||||||||||
Other |
| (2 | %) | (1 | %) | (2 | %) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Effective income tax rate |
55 | % | 32 | % | 51 | % | (32 | %) | ||||||||
|
|
|
|
|
|
|
|
In the second quarter of 2014, Devon recognized $247 million of additional income tax expense related to the $2.8 billion of repatriations to the U.S. Prior to the repatriation, Devon had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, Devon retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax in the second quarter.
In the first quarter of 2014, Devon recorded a $48 million deferred tax liability in conjunction with the formation of EnLink, which impacted the effective tax rate as reflected in the table above.
In the second quarter of 2013, Devon repatriated to the U.S. $2.0 billion of cash from its foreign subsidiaries. In conjunction with the repatriation, Devon recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.
8. Earnings (Loss) Per Share Attributable to Devon
The following table reconciles net earnings (loss) attributable to Devon and common shares outstanding used in the calculations of basic and diluted earnings per share.
Common | Earnings (loss) | |||||||||||
Earnings (loss) | Shares | per Share | ||||||||||
(In millions, except per share amounts) | ||||||||||||
Three Months Ended June 30, 2014: |
||||||||||||
Net earnings attributable to Devon |
$ | 675 | 408 | |||||||||
Attributable to participating securities |
(8 | ) | (4 | ) | ||||||||
|
|
|
|
|||||||||
Basic earnings per share |
667 | 404 | $ | 1.65 | ||||||||
Dilutive effect of potential common shares issuable |
| 2 | ||||||||||
|
|
|
|
|||||||||
Diluted earnings per share |
$ | 667 | 406 | $ | 1.64 | |||||||
|
|
|
|
|||||||||
Three Months Ended June 30, 2013: |
||||||||||||
Net earnings attributable to Devon |
$ | 683 | 406 | |||||||||
Attributable to participating securities |
(5 | ) | (4 | ) | ||||||||
|
|
|
|
|||||||||
Basic earnings per share |
678 | 402 | $ | 1.69 | ||||||||
Dilutive effect of potential common shares issuable |
| 1 | ||||||||||
|
|
|
|
|||||||||
Diluted earnings per share |
$ | 678 | 403 | $ | 1.68 | |||||||
|
|
|
|
17
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Six Months Ended June 30, 2014: |
||||||||||||
Net earnings attributable to Devon |
$ | 999 | 408 | |||||||||
Attributable to participating securities |
(10 | ) | (4 | ) | ||||||||
|
|
|
|
|||||||||
Basic earnings per share |
989 | 404 | $ | 2.45 | ||||||||
Dilutive effect of potential common shares issuable |
| 2 | ||||||||||
|
|
|
|
|||||||||
Diluted earnings per share |
$ | 989 | 406 | $ | 2.44 | |||||||
|
|
|
|
|||||||||
Six Months Ended June 30, 2013: |
||||||||||||
Net loss attributable to Devon |
$ | (656 | ) | 406 | ||||||||
Attributable to participating securities |
(1 | ) | (4 | ) | ||||||||
|
|
|
|
|||||||||
Basic loss per share |
(657 | ) | 402 | $ | (1.63 | ) | ||||||
Dilutive effect of potential common shares issuable |
| | ||||||||||
|
|
|
|
|||||||||
Diluted loss per share |
$ | (657 | ) | 402 | $ | (1.63 | ) | |||||
|
|
|
|
Certain options to purchase shares of Devons common stock are excluded from the dilution calculation because the options are antidilutive. During the three-month and six-month periods ended June 30, 2014, 2.6 million shares and 3.4 million shares, respectively, were excluded from the diluted earnings per share calculations. During the three-month and six-month periods ended June 30, 2013, 7.6 million shares were excluded from the diluted earnings per share calculations.
9. Other Comprehensive Earnings
Components of other comprehensive earnings consist of the following:
Three Months Ended
June 30, |
Six Months Ended
June 30, |
|||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In millions) | ||||||||||||||||
Foreign currency translation: |
||||||||||||||||
Beginning accumulated foreign currency translation |
$ | 1,150 | $ | 1,813 | $ | 1,448 | $ | 1,996 | ||||||||
Change in cumulative translation adjustment |
306 | (284 | ) | (7 | ) | (475 | ) | |||||||||
Income tax benefit (expense) |
(14 | ) | 13 | 1 | 21 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Ending accumulated foreign currency translation |
1,442 | 1,542 | 1,442 | 1,542 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Pension and postretirement benefit plans: |
||||||||||||||||
Beginning accumulated pension and postretirement benefits |
(177 | ) | (221 | ) | (180 | ) | (225 | ) | ||||||||
Recognition of net actuarial loss and prior service cost in earnings (1) |
6 | 6 | 11 | 12 | ||||||||||||
Income tax expense |
(1 | ) | (1 | ) | (3 | ) | (3 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Ending accumulated pension and postretirement benefits |
(172 | ) | (216 | ) | (172 | ) | (216 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Accumulated other comprehensive earnings, net of tax |
$ | 1,270 | $ | 1,326 | $ | 1,270 | $ | 1,326 | ||||||||
|
|
|
|
|
|
|
|
(1) | These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of general and administrative expenses on the accompanying comprehensive statements of earnings (see Note 15 for additional details). |
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
10. Supplemental Information to Statements of Cash Flows
Six Months Ended
June 30, |
||||||||
2014 | 2013 | |||||||
(In millions) | ||||||||
Net change in working capital accounts: |
||||||||
Accounts receivable |
$ | (234 | ) | $ | (300 | ) | ||
Other current assets |
(30 | ) | 72 | |||||
Accounts payable |
45 | 56 | ||||||
Revenues and royalties payable |
508 | 82 | ||||||
Other current liabilities |
181 | (38 | ) | |||||
|
|
|
|
|||||
Net change in working capital |
$ | 470 | $ | (128 | ) | |||
|
|
|
|
|||||
Interest paid (net of capitalized interest) |
$ | 235 | $ | 208 | ||||
Income taxes paid (received) |
$ | 113 | $ | (2 | ) |
On March 7, 2014, Devon completed a business combination to form EnLink. With the exception of a $100 million cash payment to noncontrolling interests, the business combination was a non-monetary transaction. See Note 2 for additional details.
11. Accounts Receivable
The components of accounts receivable include the following:
June 30, 2014 | December 31, 2013 | |||||||
(In millions) | ||||||||
Oil, gas and NGL sales |
$ | 1,022 | $ | 851 | ||||
Joint interest billings |
468 | 447 | ||||||
Marketing and midstream revenues |
773 | 172 | ||||||
Other |
49 | 61 | ||||||
|
|
|
|
|||||
Gross accounts receivable |
2,312 | 1,531 | ||||||
Allowance for doubtful accounts |
(11 | ) | (11 | ) | ||||
|
|
|
|
|||||
Net accounts receivable |
$ | 2,301 | $ | 1,520 | ||||
|
|
|
|
12. Goodwill
The table below provides a summary of Devons goodwill, by assigned reporting unit.
June 30, 2014 | December 31, 2013 | |||||||
(In millions) | ||||||||
U.S. |
$ | 2,618 | $ | 2,618 | ||||
Canada |
2,096 | 2,838 | ||||||
EnLink |
3,694 | 402 | ||||||
|
|
|
|
|||||
Total |
$ | 8,408 | $ | 5,858 | ||||
|
|
|
|
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
The changes to Devons goodwill during the first six months of 2014 relate to both EnLink and Canada. Included in the assets Devon contributed to EnLink Holdings was $402 million of goodwill. The additional EnLink goodwill of $3.3 billion represents the goodwill recognized on the EnLink transaction described in Note 2.
The decrease in Devons Canadian goodwill was primarily due to goodwill that was derecognized upon the asset divestitures described in Note 2.
13. Debt
June 30, 2014 | December 31, 2013 | |||||||
(In millions) | ||||||||
Devon debt |
||||||||
Commercial paper |
$ | 456 | $ | 1,317 | ||||
5.625% due January 15, 2014 |
| 500 | ||||||
Floating rate due December 15, 2015 |
500 | 500 | ||||||
2.40% due July 15, 2016 |
500 | 500 | ||||||
Floating rate due December 15, 2016 |
350 | 350 | ||||||
1.20% due December 15, 2016 |
650 | 650 | ||||||
1.875% due May 15, 2017 |
750 | 750 | ||||||
8.25% due July 1, 2018 |
125 | 125 | ||||||
2.25% due December 15, 2018 |
750 | 750 | ||||||
6.30% due January 15, 2019 |
700 | 700 | ||||||
4.00% due July 15, 2021 |
500 | 500 | ||||||
3.25% due May 15, 2022 |
1,000 | 1,000 | ||||||
7.50% due September 15, 2027 |
150 | 150 | ||||||
7.875% due September 30, 2031 |
1,250 | 1,250 | ||||||
7.95% due April 15, 2032 |
1,000 | 1,000 | ||||||
5.60% due July 15, 2041 |
1,250 | 1,250 | ||||||
4.75% due May 15, 2042 |
750 | 750 | ||||||
Net discount on debentures and notes |
(20 | ) | (20 | ) | ||||
|
|
|
|
|||||
Total Devon debt |
10,661 | 12,022 | ||||||
|
|
|
|
|||||
EnLink debt |
||||||||
Credit facilities |
255 | | ||||||
Other borrowings |
24 | | ||||||
2.70% due April 1, 2019 |
400 | | ||||||
7.125% due June 1, 2022 |
197 | | ||||||
4.40% due April 1, 2024 |
450 | | ||||||
5.60% due April 1, 2044 |
350 | | ||||||
Net premium on debentures and notes |
18 | | ||||||
|
|
|
|
|||||
Total EnLink debt |
1,694 | | ||||||
|
|
|
|
|||||
Total debt |
12,355 | 12,022 | ||||||
Less amount classified as short-term debt (1) |
475 | 4,066 | ||||||
|
|
|
|
|||||
Total long-term debt |
$ | 11,880 | $ | 7,956 | ||||
|
|
|
|
(1) | Short-term debt as of June 30, 2014 consists of $456 million of commercial paper and $19 million of EnLinks 2022 senior notes, which were redeemed on July 20, 2014. Short-term debt as of December 31, 2013 consists of $2.25 billion of senior notes issued in conjunction with the GeoSouthern acquisition, $1.3 billion of commercial paper and $500 million of senior notes due January 15, 2014. Subsequent to the close of the GeoSouthern acquisition the $2.25 billion of senior notes were reclassified to long-term debt. |
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Commercial Paper
As of June 30, 2014, Devon had $456 million of outstanding commercial paper at an average rate of 0.24 percent.
Credit Lines
Devon has a $3.0 billion syndicated, unsecured revolving line of credit (the Senior Credit Facility). As of June 30, 2014, there were 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, as defined in the credit agreement, to be no greater than 65 percent. As of June 30, 2014, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 23.4 percent.
Term Loans
In December 2013, in conjunction with the GeoSouthern acquisition, Devon entered into a term loan agreement with a group of major financial institutions. In February 2014, Devon drew $2.0 billion of term loans to finance, in part, the GeoSouthern acquisition and to pay transaction costs. The term loans were repaid on June 30, 2014 with the Canadian divestiture proceeds that were repatriated to the U.S. in June 2014.
EnLink Debt
The table below summarizes the fair value of EnLinks debt as of March 7, 2014, the formation date of EnLink. The premiums are being amortized using the effective interest method. EnLinks debt is non-recourse to Devon.
March 7, 2014
Fair Value of Debt |
Effective
Rate of Debt |
|||||||
(In millions) | ||||||||
8.875% due February 15, 2018 (principal of $725 million) (1) |
$ | 760 | 7.7 | % | ||||
7.125% due June 1, 2022 (principal of $197 million) |
226 | 5.3 | % | |||||
Credit facilities |
468 | |||||||
|
|
|||||||
Total long-term debt |
$ | 1,454 | ||||||
|
|
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
(1) | The 2018 senior notes were redeemed on April 18, 2014. |
The Partnership has a $1.0 billion unsecured revolving credit facility, which includes a $500 million letter of credit subfacility. As of June 30, 2014, there were $14.1 million in outstanding letters of credit and $160.0 million outstanding borrowings under the $1.0 billion credit facility, leaving $825.9 million available for future borrowing.
The $1.0 billion credit facility will mature on the fifth anniversary of the initial funding date, which was March 7, 2014, unless EnLink requests, and the requisite lenders agree, to extend it pursuant to its terms. The credit facility contains certain financial, operational and legal covenants. Among other things, these covenants include maintaining a ratio of consolidated indebtedness to EnLinks consolidated EBITDA (as defined in the credit facility, which definition includes projected EnLink EBITDA from certain capital expansion projects) of no more than 5.0 to 1.0. If EnLink consummates one or more acquisitions in which the aggregate purchase price is $50 million or more, the maximum allowed ratio of consolidated indebtedness to EnLinks consolidated EBITDA will increase to 5.5 to 1.0 for the quarter of the acquisition and the three following quarters.
EnLink also has a $250 million revolving credit facility, which includes a $125 million letter of credit subfacility, as well as an additional credit agreement in association with E2 Energy Services LLC under which EnLink can borrow up to $20 million. On April 9, 2014, the credit agreement was amended to increase the borrowing capacity to $30 million. As of June 30, 2014, EnLinks outstanding borrowings under the $250 million credit facility were $95 million and $23 million in association with the E2 Energy Services LLC credit agreement. Additionally, as of June 30, 2014, E2 Services had certain promissory notes outstanding related to its vehicle fleet in the amount of $0.5 million due in increments through July 2017.
The $250 million credit facility will mature on March 7, 2019. The credit facility contains certain financial, operational and legal covenants. The financial covenants will be tested on a quarterly basis, based on the rolling four-quarter period that ends on the last day of each fiscal quarter, and include (i) maintaining a maximum consolidated leverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated funded indebtedness to consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges) of 4.00 to 1.00, provided that the maximum consolidated leverage ratio is 4.50 to 1.00 during an acquisition period (as defined in the credit facility) and (ii) maintaining a minimum consolidated interest coverage ratio (as defined in the credit facility, but generally computed as the ratio of consolidated earnings before interest, taxes, depreciation, amortization and certain other non-cash charges to consolidated interest charges) of 2.50 to 1.00 at all times prior to the occurrence of an investment grade event (as defined in the credit facility).
14. Asset Retirement Obligations
The schedule below summarizes changes in Devons asset retirement obligations.
Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
(In millions) | ||||||||
Asset retirement obligations as of beginning of period |
$ | 2,228 | $ | 2,095 | ||||
Liabilities incurred |
64 | 67 | ||||||
Liabilities settled |
(22 | ) | (40 | ) | ||||
Revision of estimated obligation |
69 | 105 | ||||||
Liabilities assumed by others |
(731 | ) | (4 | ) | ||||
Accretion expense on discounted obligation |
50 | 57 | ||||||
Foreign currency translation adjustment |
(26 | ) | (72 | ) | ||||
|
|
|
|
|||||
Asset retirement obligations as of end of period |
1,632 | 2,208 | ||||||
Less current portion |
91 | 87 | ||||||
|
|
|
|
|||||
Asset retirement obligations, long-term |
$ | 1,541 | $ | 2,121 | ||||
|
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
During the first six months of 2014, Devon reduced its asset retirement obligations approximately $700 million for those obligations that were assumed by the purchasers of Devons Canadian oil and gas properties.
15. Retirement Plans
The following table presents the components of net periodic benefit cost for Devons pension and postretirement benefit plans.
(1) | These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period. |
(2) | Net periodic benefit cost is a component of general and administrative expenses on the accompanying comprehensive statements of earnings. |
16. Stockholders Equity
Dividends
Devon paid common stock dividends of $189 million and $170 million in the first six months of 2014 and 2013, respectively. The quarterly cash dividend was $0.20 per share in the first quarter of 2013. Devon increased the dividend rate to $0.22 per share in the second quarter of 2013 and to $0.24 per share in the second quarter of 2014.
Distributions to noncontrolling interests
In conjunction with the formation of EnLink in the first quarter of 2014, Devon made a payment of $100 million to noncontrolling interests. Further, EnLink distributed $41 million to its non-Devon unitholders during the first six months of 2014.
Issuance of subsidiary units
In May 2014, the Partnership entered into an Equity Distribution Agreement (the EDA) with BMO Capital Markets Corp. (BMOCM). Pursuant to the terms of the EDA, the Partnership may from time to time through BMOCM, as its sales agent, sell common units representing limited partner interests having an aggregate offering price of up to $75 million.
Through June 30, 2014, the Partnership sold an aggregate of 0.6 million common units under the EDA, generating proceeds of approximately $20 million. The Partnership used the net proceeds for general partnership purposes, including working capital, capital expenditures and repayments of indebtedness.
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
17. 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. Actual amounts could differ materially from managements estimates.
Royalty Matters
Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. The suits allege that the producers and related parties used below-market prices, made improper deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.
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 remediation costs. Devons monetary exposure for environmental matters is not expected to be material.
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.
18. Fair Value Measurements
The following tables provide carrying value and fair value measurement information for certain of Devons financial assets and liabilities. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying balance sheets approximated fair value at June 30, 2014 and December 31, 2013. Therefore, such financial assets and liabilities are not presented in the following tables.
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Commodity derivatives |
$ | 103 | $ | 103 | $ | | $ | 103 | $ | | ||||||||||
Commodity derivatives |
$ | (120 | ) | $ | (120 | ) | $ | | $ | (120 | ) | $ | | |||||||
Foreign currency derivatives |
$ | (1 | ) | $ | (1 | ) | $ | | $ | (1 | ) | $ | | |||||||
Debt |
$ | (12,022 | ) | $ | (12,908 | ) | $ | | $ | (12,908 | ) | $ | |
The following methods and assumptions were used to estimate the fair values in the tables above.
Level 1 Fair Value Measurements
Cash equivalents Amounts consist primarily of U.S. and Canadian treasury securities and money market investments. The fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents Amounts consist primarily of Canadian agency and provincial securities and commercial paper investments. The fair value approximates the carrying value.
Commodity, interest rate and foreign currency derivatives The fair values of commodity, interest rate and foreign currency derivatives are estimated using internal discounted cash flow calculations based upon forward curves and data obtained from independent third parties for contracts with similar terms or data obtained from counterparties to the agreements.
Debt Devons debt instruments do not actively trade in an established market. The fair values of its debt are estimated based on rates available for debt with similar terms and maturity. The fair value of Devons commercial paper and EnLinks credit facility is the carrying value.
Capital lease obligations The fair value was calculated using inputs from third-party banks.
Level 3 Fair Value Measurements
Long-term investments Devons long-term investments as of December 31, 2013 consisted entirely of auction rate securities. In the first quarter of 2014, Devon redeemed all these securities for approximately $57 million, or $5 million below their carrying value.
19. Segment Information
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devons Canadian operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devons U.S. and Canadian segments are all primarily engaged in oil and gas exploration and production activities.
With the formation of EnLink in the first quarter of 2014, Devon considers EnLink to be an operating segment that is distinct from its existing operating segments. EnLinks operations consist of midstream assets and operations located across the U.S. Additionally, EnLink has a management team that is primarily responsible for capital and resource allocation decisions. Therefore, EnLink is presented as a separate reporting segment. For the reporting periods prior to the formation of EnLink, Devon has reclassified, from its U.S. segment to the EnLink segment, all asset-level amounts related to the midstream assets that it contributed to EnLink Holdings.
25
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
U.S. | Canada | EnLink | Eliminations | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
Three Months Ended June 30, 2014: |
||||||||||||||||||||
Revenues from external customers |
$ | 3,252 | $ | 506 | $ | 752 | $ | | $ | 4,510 | ||||||||||
Intersegment revenues |
$ | | $ | | $ | 175 | $ | (175 | ) | $ | | |||||||||
Depreciation, depletion and amortization |
$ | 642 | $ | 112 | $ | 74 | $ | | $ | 828 | ||||||||||
Interest expense |
$ | 108 | $ | 22 | $ | 14 | $ | (11 | ) | $ | 133 | |||||||||
Earnings before income taxes |
$ | 362 | $ | 1,109 | $ | 83 | $ | | $ | 1,554 | ||||||||||
Income tax expense |
$ | 378 | $ | 458 | $ | 18 | $ | | $ | 854 | ||||||||||
Net earnings (loss) |
$ | (16 | ) | $ | 651 | $ | 65 | $ | | $ | 700 | |||||||||
Noncontrolling interests |
$ | 1 | $ | | $ | 24 | $ | | $ | 25 | ||||||||||
Net earnings (loss) attributable to Devon |
$ | (17 | ) | $ | 651 | $ | 41 | $ | | $ | 675 | |||||||||
Capital expenditures |
$ | 1,432 | $ | 278 | $ | 216 | $ | | $ | 1,926 | ||||||||||
Three Months Ended June 30, 2013: |
||||||||||||||||||||
Revenues from external customers |
$ | 2,127 | $ | 722 | $ | 239 | $ | | $ | 3,088 | ||||||||||
Intersegment revenues |
$ | | $ | | $ | 349 | $ | (349 | ) | $ | | |||||||||
Depreciation, depletion and amortization |
$ | 419 | $ | 209 | $ | 46 | $ | | $ | 674 | ||||||||||
Interest expense |
$ | 94 | $ | 23 | $ | | $ | (9 | ) | $ | 108 | |||||||||
Asset impairments |
$ | | $ | 40 | $ | | $ | | $ | 40 | ||||||||||
Earnings before income taxes |
$ | 849 | $ | 102 | $ | 46 | $ | | $ | 997 | ||||||||||
Income tax expense |
$ | 277 | $ | 20 | $ | 17 | $ | | $ | 314 | ||||||||||
Net earnings |
$ | 572 | $ | 82 | $ | 29 | $ | | $ | 683 | ||||||||||
Capital expenditures |
$ | 1,087 | $ | 356 | $ | 53 | $ | | $ | 1,496 | ||||||||||
Six Months Ended June 30, 2014: |
||||||||||||||||||||
Revenues from external customers |
$ | 5,868 | $ | 1,190 | $ | 1,177 | $ | | $ | 8,235 | ||||||||||
Intersegment revenues |
$ | | $ | | $ | 473 | $ | (473 | ) | $ | | |||||||||
Depreciation, depletion and amortization |
$ | 1,139 | $ | 306 | $ | 122 | $ | | $ | 1,567 | ||||||||||
Interest expense |
$ | 208 | $ | 41 | $ | 19 | $ | (20 | ) | $ | 248 | |||||||||
Earnings before income taxes |
$ | 758 | $ | 1,201 | $ | 155 | $ | | $ | 2,114 | ||||||||||
Income tax expense |
$ | 564 | $ | 479 | $ | 42 | $ | | $ | 1,085 | ||||||||||
Net earnings |
$ | 194 | $ | 722 | $ | 113 | $ | | $ | 1,029 | ||||||||||
Net earnings attributable to noncontrolling interests |
$ | 1 | $ | | $ | 29 | $ | | $ | 30 | ||||||||||
Net earnings attributable to Devon |
$ | 193 | $ | 722 | $ | 84 | $ | | $ | 999 | ||||||||||
Property and equipment, net |
$ | 25,606 | $ | 7,009 | $ | 4,384 | $ | | $ | 36,999 | ||||||||||
Total assets |
$ | 30,631 | $ | 11,224 | $ | 9,379 | $ | (119 | ) | $ | 51,115 | |||||||||
Capital expenditures |
$ | 8,535 | $ | 720 | $ | 284 | $ | | $ | 9,539 | ||||||||||
Six Months Ended June 30, 2013: |
||||||||||||||||||||
Revenues from external customers |
$ | 3,346 | $ | 1,261 | $ | 452 | $ | | $ | 5,059 | ||||||||||
Intersegment revenues |
$ | | $ | | $ | 663 | $ | (663 | ) | $ | | |||||||||
Depreciation, depletion and amortization |
$ | 843 | $ | 444 | $ | 91 | $ | | $ | 1,378 | ||||||||||
Interest expense |
$ | 190 | $ | 42 | $ | | $ | (14 | ) | $ | 218 | |||||||||
Asset impairments |
$ | 1,110 | $ | 843 | $ | | $ | | $ | 1,953 | ||||||||||
Earnings (loss) before income taxes |
$ | (270 | ) | $ | (778 | ) | $ | 83 | $ | | $ | (965 | ) | |||||||
Income tax expense (benefit) |
$ | (131 | ) | $ | (208 | ) | $ | 30 | $ | | $ | (309 | ) | |||||||
Net earnings (loss) |
$ | (139 | ) | $ | (570 | ) | $ | 53 | $ | | $ | (656 | ) | |||||||
Capital expenditures |
$ | 2,258 | $ | 940 | $ | 136 | $ | | $ | 3,334 | ||||||||||
December 31, 2013: |
||||||||||||||||||||
Property and equipment, net |
$ | 18,201 | $ | 8,478 | $ | 1,768 | $ | | $ | 28,447 | ||||||||||
Total assets |
$ | 27,080 | $ | 13,560 | $ | 2,237 | $ | | $ | 42,877 |
26
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 and six-month periods ended June 30, 2014, compared to the three-month and six-month periods ended June 30, 2013, and in our financial condition and liquidity since December 31, 2013. For information regarding our critical accounting policies and estimates, see our 2013 Annual Report on Form 10-K under Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Overview of 2014 Results
Key components of our financial performance are summarized below.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
($ in millions, except per share amounts) | ||||||||||||||||||||||||
Net earnings (loss) attributable to Devon |
$ | 675 | $ | 683 | -1 | % | $ | 999 | $ | (656 | ) | +252 | % | |||||||||||
Adjusted earnings attributable to Devon (1) |
$ | 574 | $ | 491 | +17 | % | $ | 1,121 | $ | 761 | +47 | % | ||||||||||||
Earnings (loss) per share attributable to Devon |
$ | 1.64 | $ | 1.68 | -2 | % | $ | 2.44 | $ | (1.63 | ) | +249 | % | |||||||||||
Adjusted earnings per share attributable to Devon (1) |
$ | 1.40 | $ | 1.21 | +16 | % | $ | 2.74 | $ | 1.87 | +46 | % | ||||||||||||
Production (MBoe/d) |
667 | 698 | -4 | % | 679 | 692 | -2 | % | ||||||||||||||||
Realized price per Boe |
$ | 44.12 | $ | 35.00 | +26 | % | $ | 42.61 | $ | 32.13 | +33 | % | ||||||||||||
Adjusted operating income per Boe (2) |
$ | 28.69 | $ | 22.05 | +30 | % | $ | 27.05 | $ | 20.13 | +34 | % | ||||||||||||
Operating cash flow |
$ | 2,049 | $ | 1,396 | +47 | % | $ | 3,459 | $ | 2,398 | +44 | % | ||||||||||||
Capitalized costs |
$ | 1,926 | $ | 1,496 | +29 | % | $ | 9,539 | $ | 3,334 | +186 | % | ||||||||||||
Shareholder distributions |
$ | 99 | $ | 88 | +11 | % | $ | 189 | $ | 170 | +11 | % |
(1) | Adjusted earnings and adjusted earnings per share attributable to Devon are financial measures not prepared in accordance with accounting principles generally accepted in the U.S. (GAAP). For a description of adjusted earnings and adjusted earnings per share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see Non-GAAP Measures in this Item 2. |
(2) | Computed as revenues from commodity sales, commodity derivatives settlements and marketing and midstream operations, less expenses for lease operations, marketing and midstream operations, general and administrative, production and property taxes and net financing costs, with the result divided by total production. |
During the three-month and six-month periods ended June 30, 2014, our adjusted earnings, adjusted earnings per share and adjusted operating income per Boe all increased compared to the same periods in 2013. The improved 2014 results were driven primarily by increases in oil and gas prices, liquids volumes and oil and gas realizations. These factors also contributed to higher operating cash flow which caused our cash flow deficit to narrow considerably in 2014.
During the first six months of 2014, we made significant progress toward three strategic initiatives that are focused on building value per share. On February 28, 2014, we closed the GeoSouthern acquisition and acquired GeoSoutherns Eagle Ford Shale assets and operations in south Texas for approximately $6.0 billion. This acquisition included approximately 250 MMBoe of proved reserves. Additionally, since closing the transaction, we have produced over 7 MMBoe from our Eagle Ford development, with oil accounting for over 60% of our production from the play.
On March 7, 2014, we, Crosstex Energy, Inc. and Crosstex Energy, L.P. (collectively Crosstex) completed a transaction to combine substantially all of our U.S. midstream assets with Crosstexs assets to form a new midstream business referred to as EnLink. This transaction, including Devons controlling ownership of EnLink, is described more fully in Part I. Financial Information Item 1. Financial Statements Note 2 in this report. The results of operations from our assets contributed to EnLink are included in our consolidated financial statements for all periods presented. Additionally, the results of operations for all assets contributed to EnLink are included in our consolidated financial statements subsequent to the completion of the transaction. The portions of EnLinks net earnings and stockholders equity not attributable to Devons controlling interest are shown separately as noncontrolling interests in our consolidated comprehensive statements of earnings and consolidated balance sheets.
27
Finally, we are nearing completion of our non-core divestiture program. On April 1, 2014, we sold Canadian conventional assets to Canadian Natural Resources Limited for $2.8 billion ($3.125 billion Canadian dollars). This divestiture included approximately 170 MMBoe of proved reserves. Production associated with the divested properties was approximately 79 MBoe/d, including 357 MMcf/d of natural gas in the first quarter of 2014. Additionally, on June 30, 2014, we reached an agreement with Linn Energy to sell our U.S. non-core assets for $2.3 billion. This transaction is expected to close in the third quarter of 2014.
In the second quarter, we repatriated $2.8 billion to the U.S. from the Canadian divestiture. We used those proceeds, cash on hand and free cash flow generated during the quarter to reduce debt balances by $3.2 billion.
28
Results of Operations
Oil, Gas and NGL Production
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
Oil (MBbls/d) |
||||||||||||||||||||||||
Anadarko Basin |
11 | 9 | +24 | % | 10 | 9 | +17 | % | ||||||||||||||||
Barnett Shale |
2 | 2 | -13 | % | 2 | 2 | +5 | % | ||||||||||||||||
Eagle Ford |
40 | | N/M | 25 | | N/M | ||||||||||||||||||
Mississippian-Woodford Trend |
9 | 3 | +162 | % | 9 | 3 | +240 | % | ||||||||||||||||
Permian Basin |
55 | 46 | +21 | % | 55 | 43 | +28 | % | ||||||||||||||||
Rockies |
8 | 8 | -0 | % | 8 | 7 | +8 | % | ||||||||||||||||
Other |
3 | 3 | +0 | % | 3 | 3 | +0 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
U.S. core and emerging properties |
128 | 71 | +79 | % | 112 | 67 | +68 | % | ||||||||||||||||
Canada |
25 | 29 | -9 | % | 26 | 28 | -8 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total core and emerging properties |
153 | 100 | +54 | % | 138 | 95 | +45 | % | ||||||||||||||||
Non-core properties |
4 | 16 | -73 | % | 10 | 17 | -42 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total |
157 | 116 | +36 | % | 148 | 112 | +32 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Bitumen (MBbls/d) |
||||||||||||||||||||||||
Canada |
52 | 53 | -3 | % | 52 | 54 | -4 | % | ||||||||||||||||
Gas (MMcf/d) |
||||||||||||||||||||||||
Anadarko Basin |
309 | 281 | +10 | % | 295 | 275 | +7 | % | ||||||||||||||||
Barnett Shale |
932 | 1,040 | -10 | % | 931 | 1,049 | -11 | % | ||||||||||||||||
Eagle Ford |
86 | | N/M | 54 | | N/M | ||||||||||||||||||
Mississippian-Woodford Trend |
28 | 8 | +239 | % | 28 | 7 | +320 | % | ||||||||||||||||
Permian Basin |
134 | 106 | +26 | % | 128 | 97 | +31 | % | ||||||||||||||||
Rockies |
67 | 79 | -15 | % | 68 | 77 | -11 | % | ||||||||||||||||
Other |
135 | 164 | -18 | % | 137 | 162 | -15 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
U.S. core and emerging properties |
1,691 | 1,678 | +1 | % | 1,641 | 1,667 | -2 | % | ||||||||||||||||
Canada |
23 | 32 | -26 | % | 23 | 35 | -37 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total core and emerging properties |
1,714 | 1,710 | +0 | % | 1,664 | 1,702 | -2 | % | ||||||||||||||||
Non-core properties |
217 | 730 | -70 | % | 397 | 730 | -46 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total |
1,931 | 2,440 | -21 | % | 2,061 | 2,432 | -15 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
NGLs (MBbls/d) |
||||||||||||||||||||||||
Anadarko Basin |
31 | 24 | +26 | % | 30 | 24 | +23 | % | ||||||||||||||||
Barnett Shale |
55 | 54 | +3 | % | 55 | 53 | +3 | % | ||||||||||||||||
Eagle Ford |
10 | | N/M | 7 | | N/M | ||||||||||||||||||
Mississippian-Woodford Trend |
5 | 1 | +553 | % | 5 | 1 | +893 | % | ||||||||||||||||
Permian Basin |
18 | 13 | +37 | % | 17 | 13 | +33 | % | ||||||||||||||||
Rockies |
1 | 2 | -59 | % | 1 | 1 | -24 | % | ||||||||||||||||
Other |
10 | 11 | -9 | % | 10 | 11 | -9 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
U.S. core and emerging properties |
130 | 105 | +24 | % | 125 | 103 | +21 | % | ||||||||||||||||
Non-core properties |
6 | 17 | -63 | % | 11 | 18 | -38 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total |
136 | 122 | +12 | % | 136 | 121 | +12 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Combined (MBoe/d) |
||||||||||||||||||||||||
Anadarko Basin |
93 | 80 | +16 | % | 89 | 79 | +13 | % | ||||||||||||||||
Barnett Shale |
212 | 230 | -7 | % | 212 | 230 | -8 | % | ||||||||||||||||
Eagle Ford |
65 | | N/M | 41 | | N/M | ||||||||||||||||||
Mississippian-Woodford Trend |
18 | 5 | +236 | % | 19 | 4 | +335 | % | ||||||||||||||||
Permian Basin |
95 | 76 | +25 | % | 93 | 72 | +30 | % | ||||||||||||||||
Rockies |
21 | 24 | -14 | % | 21 | 22 | -5 | % | ||||||||||||||||
Other |
35 | 41 | -15 | % | 36 | 41 | -12 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
U.S. core and emerging properties |
539 | 456 | +18 | % | 511 | 448 | +14 | % | ||||||||||||||||
Canada |
81 | 87 | -6 | % | 81 | 88 | -8 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total core and emerging properties |
620 | 543 | +14 | % | 592 | 536 | +10 | % | ||||||||||||||||
Non-core properties |
47 | 155 | -70 | % | 87 | 156 | -44 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total |
667 | 698 | -4 | % | 679 | 692 | -2 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
29
Oil, Gas and NGL Pricing
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 (1) | 2013 (1) | Change | 2014 (1) | 2013 (1) | Change | |||||||||||||||||||
Oil (per Bbl) |
||||||||||||||||||||||||
U.S. |
$ | 95.71 | $ | 91.56 | +5 | % | $ | 93.96 | $ | 89.64 | +5 | % | ||||||||||||
Canada |
$ | 76.60 | $ | 72.47 | +6 | % | $ | 73.48 | $ | 64.76 | +13 | % | ||||||||||||
Total |
$ | 92.59 | $ | 85.02 | +9 | % | $ | 89.64 | $ | 80.73 | +11 | % | ||||||||||||
Bitumen (per Bbl) |
||||||||||||||||||||||||
Canada |
$ | 65.88 | $ | 53.90 | +22 | % | $ | 60.47 | $ | 41.10 | +47 | % | ||||||||||||
Gas (per Mcf) |
||||||||||||||||||||||||
U.S. |
$ | 4.19 | $ | 3.49 | +20 | % | $ | 4.26 | $ | 3.15 | +35 | % | ||||||||||||
Canada (2) |
$ | 1.56 | $ | 3.44 | -55 | % | $ | 3.97 | $ | 3.24 | +23 | % | ||||||||||||
Total |
$ | 4.15 | $ | 3.48 | +19 | % | $ | 4.23 | $ | 3.17 | +34 | % | ||||||||||||
NGLs (per Bbl) |
||||||||||||||||||||||||
U.S. |
$ | 25.22 | $ | 24.80 | +2 | % | $ | 27.34 | $ | 25.53 | +7 | % | ||||||||||||
Canada |
$ | | $ | 43.68 | N/M | $ | 50.17 | $ | 45.54 | +10 | % | |||||||||||||
Total |
$ | 25.13 | $ | 26.29 | -4 | % | $ | 28.11 | $ | 27.16 | +4 | % | ||||||||||||
Combined (per Boe) |
||||||||||||||||||||||||
U.S. |
$ | 41.06 | $ | 32.19 | +28 | % | $ | 40.30 | $ | 30.29 | +33 | % | ||||||||||||
Canada |
$ | 65.96 | $ | 43.02 | +53 | % | $ | 53.26 | $ | 37.34 | +43 | % | ||||||||||||
Total |
$ | 44.12 | $ | 35.00 | +26 | % | $ | 42.61 | $ | 32.13 | +33 | % |
(1) | The prices presented exclude any effects due to oil, gas and NGL derivatives. |
(2) | The reported Canadian gas volumes include 19 and 27 MMcf per day for the second quarter of 2014 and 2013, respectively, and 29 and 28 MMcf per day for the first six months of 2014 and 2013, respectively, that are produced from certain of our leases and then transported to our Jackfish operations where the gas is used as fuel. However, the revenues and expenses related to this consumed gas are eliminated in our consolidated financial results. With the sale of the vast majority of the Canadian gas business in the second quarter of 2014, the impact of the eliminated gas revenues more significantly impacts our gas price. |
30
Commodity Sales
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the three months ended June 30, 2014 and 2013 .
Three Months Ended June 30, | ||||||||||||||||||||
Oil | Bitumen | Gas | NGLs | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
2013 sales |
$ | 897 | $ | 260 | $ | 773 | $ | 292 | $ | 2,222 | ||||||||||
Change due to volumes |
323 | (8 | ) | (161 | ) | 33 | 187 | |||||||||||||
Change due to prices |
108 | 57 | 119 | (14 | ) | 270 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
2014 sales |
$ | 1,328 | $ | 309 | $ | 731 | $ | 311 | $ | 2,679 | ||||||||||
|
|
|
|
|
|
|
|
|
|
Upstream sales increased $187 million due to volumes in the second quarter of 2014. The primary driver of the increase results from a 79% increase in our U.S. core and emerging oil production. Such growth results from our recently acquired Eagle Ford Shale properties and the continued development of our Permian Basin and Mississippian-Woodford Trend properties. In addition, we continue to grow our NGL production from these plays, which resulted in $33 million of additional sales. These production additions were partially offset by the impacts of our Canadian divestitures, which were the primary driver of our 21% decrease in gas production. Bitumen sales decreased due to volumes as a result of higher royalties on our Jackfish heavy oil project in Canada.
Upstream sales increased $270 million due to prices in the second quarter of 2014, primarily due to a 26% increase in our realized price without hedges. Oil and bitumen sales were the most significantly impacted with an increase of $166 million, largely due to higher prices and realizations resulting from a higher average NYMEX West Texas Intermediate index price and tighter bitumen and heavy oil differentials. Gas sales increased $119 million largely due to higher North American regional index prices upon which our gas sales are based. NGL sales decreased $14 million as a result of lower NGL prices at Mont Belvieu, Texas.
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between the six months ended June 30, 2014 and 2013 .
Six Months Ended June 30, | ||||||||||||||||||||
Oil | Bitumen | Gas | NGLs | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
2013 sales |
$ | 1,636 | $ | 400 | $ | 1,394 | $ | 596 | $ | 4,026 | ||||||||||
Change due to volumes |
528 | (16 | ) | (213 | ) | 71 | 370 | |||||||||||||
Change due to prices |
239 | 181 | 396 | 24 | 840 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
2014 sales |
$ | 2,403 | $ | 565 | $ | 1,577 | $ | 691 | $ | 5,236 | ||||||||||
|
|
|
|
|
|
|
|
|
|
Upstream sales increased $370 million due to volumes during the first six months of 2014. The primary driver of the increase results from a 68% increase in our U.S. core and emerging oil production. Such growth results from our recently acquired Eagle Ford Shale properties and the continued development of our Permian Basin and Mississippian-Woodford Trend properties. In addition, we continue to grow our NGL production from these plays, which resulted in $71 million of additional sales. These production additions were partially offset by the impacts of our Canadian divestitures, which were the primary driver of our 15% decrease in gas production. Bitumen sales decreased due to volumes as a result of higher royalties on our Jackfish heavy oil project in Canada.
Upstream sales increased $840 million due to prices during the first six months of 2014, primarily due to a 33% increase in our realized price without hedges. Oil and bitumen sales were the most significantly impacted with an increase of $420 million, largely due to higher prices and realizations resulting from a higher average NYMEX West Texas Intermediate index price and tighter bitumen and heavy oil differentials. Gas sales increased $396 million largely due to higher North American regional index prices upon which our gas sales are based. NGL sales increased $24 million as a result of higher NGL prices at Mont Belvieu, Texas.
31
Oil, Gas and NGL Derivatives
A summary of our open commodity derivative positions is included in Note 3 to the financial statements included in Item 1. Consolidated Financial Statements of this report. The following tables provide financial information associated with our commodity derivatives. The first table presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, bitumen, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In millions) | ||||||||||||||||
Cash settlements: |
||||||||||||||||
Oil derivatives |
$ | (79 | ) | $ | 29 | $ | (115 | ) | $ | 61 | ||||||
Gas derivatives |
(29 | ) | (17 | ) | (93 | ) | 36 | |||||||||
NGL derivatives |
| 2 | | 3 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total cash settlements |
(108 | ) | 14 | (208 | ) | 100 | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Gains (losses) on fair value changes: |
||||||||||||||||
Oil derivatives |
(320 | ) | 43 | (409 | ) | (104 | ) | |||||||||
Gas derivatives |
29 | 308 | (102 | ) | 52 | |||||||||||
NGL derivatives |
| 1 | | (2 | ) | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total gains (losses) on fair value changes |
(291 | ) | 352 | (511 | ) | (54 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Oil, gas and NGL derivatives |
$ | (399 | ) | $ | 366 | $ | (719 | ) | $ | 46 | ||||||
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2014 | ||||||||||||||||||||
Oil
(Per Bbl) |
Bitumen
(Per Bbl) |
Gas
(Per Mcf) |
NGLs
(Per Bbl) |
Boe
(Per Boe) |
||||||||||||||||
Realized price without hedges |
$ | 92.59 | $ | 65.88 | $ | 4.15 | $ | 25.13 | $ | 44.12 | ||||||||||
Cash settlements of hedges (1) |
(5.54 | ) | | (0.16 | ) | | (1.78 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Realized price, including cash settlements |
$ | 87.05 | $ | 65.88 | $ | 3.99 | $ | 25.13 | $ | 42.34 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Three Months Ended June 30, 2013 | ||||||||||||||||||||
Oil
(Per Bbl) |
Bitumen
(Per Bbl) |
Gas
(Per Mcf) |
NGLs
(Per Bbl) |
Boe
(Per Boe) |
||||||||||||||||
Realized price without hedges |
$ | 85.02 | $ | 53.90 | $ | 3.48 | $ | 26.29 | $ | 35.00 | ||||||||||
Cash settlements of hedges (1) |
2.82 | | (0.07 | ) | 0.10 | 0.23 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Realized price, including cash settlements |
$ | 87.84 | $ | 53.90 | $ | 3.41 | $ | 26.39 | $ | 35.23 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Six Months Ended June 30, 2014 | ||||||||||||||||||||
Oil
(Per Bbl) |
Bitumen
(Per Bbl) |
Gas
(Per Mcf) |
NGLs
(Per Bbl) |
Boe
(Per Boe) |
||||||||||||||||
Realized price without hedges |
$ | 89.64 | $ | 60.47 | $ | 4.23 | $ | 28.11 | $ | 42.61 | ||||||||||
Cash settlements of hedges (1) |
(4.31 | ) | | (0.25 | ) | | (1.70 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Realized price, including cash settlements |
$ | 85.33 | $ | 60.47 | $ | 3.98 | $ | 28.11 | $ | 40.91 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Six Months Ended June 30, 2013 | ||||||||||||||||||||
Oil
(Per Bbl) |
Bitumen
(Per Bbl) |
Gas
(Per Mcf) |
NGLs
(Per Bbl) |
Boe
(Per Boe) |
||||||||||||||||
Realized price without hedges |
$ | 80.73 | $ | 41.10 | $ | 3.17 | $ | 27.16 | $ | 32.13 | ||||||||||
Cash settlements of hedges (1) |
3.05 | | 0.08 | 0.11 | 0.80 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Realized price, including cash settlements |
$ | 83.78 | $ | 41.10 | $ | 3.25 | $ | 27.27 | $ | 32.93 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(1) | Cash settlements of oil hedges include settlements from our Western Canadian Select basis swaps presented in Note 3 to the financial statements included in Item 1. Consolidated Financial Statements of this report. |
32
Cash settlements as presented in the tables above represent realized gains or losses related to various commodity derivatives. In addition to cash settlements, we also recognize fair value changes on our commodity derivatives in each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationships between contract prices and the associated forward curves. Including the cash settlements discussed above, our commodity derivatives incurred a net loss of $399 million and generated a net gain of $366 million in the second quarter of 2014 and 2013, respectively. Including the cash settlements discussed above, our commodity derivatives incurred a net loss of $719 million and generated a net gain of $46 million in the first six months of 2014 and 2013, respectively.
Marketing and Midstream Revenues and Operating Expenses
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Operating revenues |
$ | 2,230 | $ | 500 | +344 | % | $ | 3,718 | $ | 987 | +276 | % | ||||||||||||
Product purchases |
(1,934 | ) | (334 | ) | +479 | % | (3,188 | ) | (647 | ) | +393 | % | ||||||||||||
Operations and maintenance expenses |
(72 | ) | (48 | ) | +50 | % | (123 | ) | (98 | ) | +26 | % | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Operating profit |
$ | 224 | $ | 118 | +90 | % | $ | 407 | $ | 242 | +68 | % | ||||||||||||
|
|
|
|
|
|
|
|
During the second quarter and first six months of 2014, marketing and midstream operating profit increased $106 million and $165 million, respectively, primarily due to higher prices and volumes. Of the $106 million increase for the three months ended June 30, $93 million was attributable to EnLinks operations. Of the $165 million increase for the six months ended June 30, $140 million was related to EnLinks operations. EnLinks Oklahoma segment, which includes the Cana plant and gathering system, was the largest driver of the increase. The remaining increase in operating profit related to Devons marketing activities.
Besides the impact to our overall operating profit, Devons marketing activities were the primary driver of the increases in both operating revenues and product purchases. The higher marketing revenues and product purchases are primarily due to commitments we have entered into to secure capacity on downstream oil pipelines. Marketing activities of EnLink also contributed to the increases noted above.
Lease Operating Expenses (LOE)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
LOE ($ in millions): |
||||||||||||||||||||||||
U.S. |
$ | 409 | $ | 307 | +33 | % | $ | 753 | $ | 595 | +26 | % | ||||||||||||
Canada |
173 | 252 | -31 | % | 427 | 489 | -13 | % | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total |
$ | 582 | $ | 559 | +4 | % | $ | 1,180 | $ | 1,084 | +9 | % | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
LOE per Boe: |
||||||||||||||||||||||||
U.S. |
$ | 7.68 | $ | 6.54 | +17 | % | $ | 7.46 | $ | 6.43 | +16 | % | ||||||||||||
Canada |
$ | 23.15 | $ | 15.25 | +52 | % | $ | 19.48 | $ | 14.92 | +31 | % | ||||||||||||
Total |
$ | 9.58 | $ | 8.80 | +9 | % | $ | 9.60 | $ | 8.65 | +11 | % |
LOE per Boe increased 9% and 11% during the second quarter and first six months of 2014, respectively. The largest contributor to the higher unit cost related to our Canadian operations. The higher Canadian unit costs largely resulted from the divestiture of the conventional assets in the second quarter of 2014 which resulted in lower total volumes while retaining the relatively higher-cost thermal heavy oil operations. The higher unit cost in the U.S. was primarily related to our liquids production growth, particularly in the Permian Basin and Mississippian-Woodford Trend, where projects generally require a higher cost to produce per unit than our gas projects. Additionally, we experienced upward pressures on costs in certain operating areas, which also contributed to the higher LOE per Boe.
33
General and Administrative Expenses (G&A)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Gross G&A |
$ | 316 | $ | 287 | +10 | % | $ | 647 | $ | 570 | +14 | % | ||||||||||||
Capitalized G&A |
(91 | ) | (85 | ) | +8 | % | (174 | ) | (183 | ) | -5 | % | ||||||||||||
Reimbursed G&A |
(36 | ) | (35 | ) | +3 | % | (73 | ) | (70 | ) | +5 | % | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Net G&A |
$ | 189 | $ | 167 | +13 | % | $ | 400 | $ | 317 | +26 | % | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Net G&A per Boe |
$ | 3.11 | $ | 2.63 | +18 | % | $ | 3.25 | $ | 2.53 | +29 | % | ||||||||||||
|
|
|
|
|
|
|
|
Net G&A and net G&A per Boe increased during the second quarter and first six months of 2014 largely due to higher employee compensation and benefits and $22 million in one-time costs in the first quarter of 2014 related to the EnLink and GeoSouthern transactions. The higher employee compensation and benefits costs were primarily related to share-based awards, which cause our G&A to be higher in the quarter in which our annual share-based grant is made. The grant related to our 2013 compensation cycle was made in the first quarter of 2014. The grant related to our 2012 compensation cycle was made in the fourth quarter of 2012. Additionally, higher employee severance costs in 2014, as well as expansion of our workforce as a part of growing production operations at certain of our key areas, also contributed to the increase.
Production and Property Taxes
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Production |
$ | 104 | $ | 71 | +46 | % | $ | 191 | $ | 131 | +45 | % | ||||||||||||
Property and other |
46 | 54 | -14 | % | 96 | 107 | -10 | % | ||||||||||||||||
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Production and property taxes |
$ | 150 | $ | 125 | +20 | % | $ | 287 | $ | 238 | +21 | % | ||||||||||||
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Percentage of oil, gas and NGL sales: |
||||||||||||||||||||||||
Production |
3.9 | % | 3.2 | % | +21 | % | 3.7 | % | 3.3 | % | +12 | % | ||||||||||||
Property and other |
1.7 | % | 2.4 | % | -29 | % | 1.8 | % | 2.6 | % | -28 | % | ||||||||||||
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Total |
5.6 | % | 5.6 | % | -0 | % | 5.5 | % | 5.9 | % | -7 | % | ||||||||||||
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Production and property taxes increased during the second quarter and first six months of 2014 primarily due to an increase in our U.S. revenues, on which the majority of our production taxes are assessed.
Depreciation, Depletion and Amortization (DD&A)
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
DD&A ($ in millions): |
||||||||||||||||||||||||
Oil & gas properties |
$ | 719 | $ | 595 | +21 | % | $ | 1,378 | $ | 1,222 | +13 | % | ||||||||||||
Other assets |
109 | 79 | +37 | % | 189 | 156 | +21 | % | ||||||||||||||||
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Total |
$ | 828 | $ | 674 | +23 | % | $ | 1,567 | $ | 1,378 | +14 | % | ||||||||||||
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DD&A per Boe: |
||||||||||||||||||||||||
Oil & gas properties |
$ | 11.85 | $ | 9.37 | +26 | % | $ | 11.21 | $ | 9.75 | +15 | % | ||||||||||||
Other assets |
1.78 | 1.25 | +43 | % | 1.54 | 1.25 | +23 | % | ||||||||||||||||
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Total |
$ | 13.63 | $ | 10.62 | +28 | % | $ | 12.75 | $ | 11.00 | +16 | % | ||||||||||||
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DD&A from our oil and gas properties increased in both 2014 periods largely due to higher DD&A rates. The higher rates resulted from our oil and gas drilling and development activities and the GeoSouthern acquisition, which were partially offset by the asset impairments recognized in the first quarter of 2013. Other DD&A increased in both periods primarily due to the EnLink transaction.
34
Asset Impairments
Six Months Ended June 30, 2013 | ||||||||
Gross | Net of Taxes | |||||||
(In millions) | ||||||||
U.S. oil and gas assets |
$ | 1,110 | $ | 707 | ||||
Canada oil and gas assets |
843 | 632 | ||||||
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|
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Total asset impairments |
$ | 1,953 | $ | 1,339 | ||||
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Oil and Gas Impairments
Under the full-cost method of accounting, capitalized costs of oil and gas properties are subject to a quarterly full-cost ceiling test. The oil and gas asset impairments resulted primarily from declines in the U.S. and Canada full-cost ceilings. The lower ceiling values resulted primarily from decreases in the 12-month average trailing prices for oil, bitumen and NGLs, which reduced proved reserve values.
Restructuring Costs
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In millions) | ||||||||||||||||
Canadian divestitures |
$ | 5 | $ | | $ | 42 | $ | | ||||||||
Office consolidation |
| 8 | | 46 | ||||||||||||
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Restructuring costs |
$ | 5 | $ | 8 | $ | 42 | $ | 46 | ||||||||
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Canadian Divestitures
In the six months ended June 30, 2014, we recognized $42 million of employee related costs associated with our Canadian non-core asset divestitures. Approximately $15 million of the employee related costs resulted from accelerated vesting of share-based grants, which are non-cash charges.
Office Consolidation
In the six months ended June 30, 2013, we incurred $46 million of restructuring costs associated with the consolidation of our U.S. personnel into one location in Oklahoma City. This amount includes $25 million related to office space that is subject to non-cancellable operating lease agreements that we ceased using as a part of the office consolidation. We also recognized $6 million of asset impairment charges for leasehold improvements and furniture associated with the office consolidation.
Gains On Asset Sales
In conjunction with the divestiture of our Canadian non-core properties, in the first six months of 2014 we recognized gains on conventional asset divestitures. Under full cost accounting rules, sales or dispositions of oil and gas properties are generally accounted for as adjustments to capitalized costs, with no recognition of gain or loss. However, if not recognizing a gain or loss on the disposition would otherwise significantly alter the relationship between a cost centers capitalized costs and proved reserves, then a gain or loss must be recognized. Our Canadian divestitures significantly altered such relationship. Therefore, we recognized a total gain of $1.1 billion ($0.6 billion after-tax) during the first six months of 2014.
35
Net Financing Costs
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||
2014 | 2013 | Change | 2014 | 2013 | Change | |||||||||||||||||||
($ in millions) | ||||||||||||||||||||||||
Interest based on debt outstanding |
$ | 141 | $ | 116 | +21 | % | $ | 266 | $ | 234 | +14 | % | ||||||||||||
Capitalized interest |
(19 | ) | (12 | ) | +53 | % | (35 | ) | (23 | ) | +53 | % | ||||||||||||
Other fees and expenses |
11 | 4 | +249 | % | 17 | 7 | +162 | % | ||||||||||||||||
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Interest expense |
$ | 133 | $ | 108 | +25 | % | $ | 248 | $ | 218 | +14 | % | ||||||||||||
Interest income |
(2 | ) | (5 | ) | -46 | % | (5 | ) | (12 | ) | -61 | % | ||||||||||||
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Net financing costs |
$ | 131 | $ | 103 | +28 | % | $ | 243 | $ | 206 | +19 | % | ||||||||||||
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|
|
Net financing costs increased during the second quarter and first six months of 2014 primarily due to higher average debt borrowings resulting from the EnLink and GeoSouthern transactions.
Income Taxes
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Total income tax expense (benefit) (in millions) |
$ | 854 | $ | 314 | $ | 1,085 | $ | (309 | ) | |||||||
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|
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U.S. statutory income tax rate |
35 | % | 35 | % | 35 | % | (35 | %) | ||||||||
Repatriations |
16 | % | | 12 | % | | ||||||||||
State income taxes |
| 1 | % | 1 | % | (1 | %) | |||||||||
Taxation on Canadian operations |
4 | % | (2 | %) | 2 | % | 6 | % | ||||||||
Taxes on EnLink formation |
| | 2 | % | | |||||||||||
Other |
| (2 | %) | (1 | %) | (2 | %) | |||||||||
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|
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Effective income tax rate |
55 | % | 32 | % | 51 | % | (32 | %) | ||||||||
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In the second quarter of 2014, we recognized $247 million of additional income tax expense related to the $2.8 billion of repatriations to the U.S. Prior to the repatriation, we had recognized a $143 million deferred income tax liability associated with the planned repatriation. When the repatriation was made, we retained a larger property basis in Canada than was previously estimated, resulting in the incremental tax in the second quarter.
In the first quarter of 2014, we recorded a $48 million deferred tax liability in conjunction with the formation of EnLink, which impacted our effective tax rate as reflected in the table above.
In the second quarter of 2013, we repatriated to the U.S. $2.0 billion of cash from our foreign subsidiaries. In conjunction with the repatriation, we recognized approximately $100 million of current income tax expense. The current expense was entirely offset by the recognition of deferred income tax benefits, which included the reduction of the deferred tax liability previously recognized for unremitted foreign earnings deemed not to be indefinitely reinvested.
36
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in our cash and short-term investments.
Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
(In millions) | ||||||||
Operating cash flow |
$ | 3,459 | $ | 2,398 | ||||
Divestitures of property and equipment |
2,942 | 34 | ||||||
Capital expenditures |
(3,341 | ) | (3,569 | ) | ||||
Acquisitions of property, equipment and businesses |
(6,224 | ) | | |||||
Debt activity, net |
(1,132 | ) | (1,495 | ) | ||||
Distributions to Devon shareholders |
(189 | ) | (170 | ) | ||||
Distributions to noncontrolling interests |
(141 | ) | | |||||
Other |
266 | 54 | ||||||
|
|
|
|
|||||
Net change in cash and short-term investments |
$ | (4,360 | ) | $ | (2,748 | ) | ||
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|
|||||
Cash and short-term investments at end of period |
$ | 1,706 | $ | 4,232 | ||||
|
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|
|
Operating Cash Flow
Net cash provided by operating activities (operating cash flow) was a significant source of capital in the first six months of 2014. Our operating cash flow increased 44 percent during 2014 primarily due to higher commodity prices, higher oil realizations and liquids production growth, partially offset by higher expenses.
Excluding the $6.2 billion attributable to the GeoSouthern and other acquisitions, our operating cash flow funded our capital expenditures during the first six months of 2014 and funded approximately 67 percent of our capital expenditures during the first six months of 2013. Leveraging our liquidity, we used cash balances and debt to fund the remainder of our 2013 cash-based capital expenditures.
Divestitures
In November 2013, we announced plans to divest certain non-core properties located throughout Canada and the U.S. In the first six months of 2014, we completed our Canadian divestiture transactions and received proceeds totaling $2.9 billion. Additionally, in the second quarter of 2014, we reached an agreement to sell our U.S. non-core assets for $2.3 billion to Linn Energy.
Capital Expenditures
The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods.
Six Months Ended June 30, | ||||||||
2014 | 2013 | |||||||
(In millions) | ||||||||
Development |
$ | 2,406 | $ | 2,510 | ||||
Exploration |
162 | 403 | ||||||
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|
|
|
|||||
Total oil and gas development and exploration |
2,568 | 2,913 | ||||||
Capitalized G&A and interest |
164 | 172 | ||||||
|
|
|
|
|||||
Total oil and gas |
2,732 | 3,085 | ||||||
Acquisitions of property, equipment and businesses |
6,224 | | ||||||
Midstream |
231 | 228 | ||||||
Corporate and other |
61 | 99 | ||||||
|
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|
|
|||||
Devon capital expenditures |
9,248 | 3,412 | ||||||
EnLink |
317 | 157 | ||||||
|
|
|
|
|||||
Total capital expenditures |
$ | 9,565 | $ | 3,569 | ||||
|
|
|
|
37
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 $8.9 billion and $3.1 billion in the first six months of 2014 and 2013, respectively. The increase in capital spending was primarily due to the GeoSouthern acquisition. Excluding this acquisition, exploration and development capital spending decreased 12 percent in the first six months of 2014, primarily due to utilization of the drilling carries in 2014 from our Sinopec and Sumitomo joint venture arrangements.
Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering systems and oil pipelines. Our midstream capital expenditures are largely impacted by our oil and gas drilling activities.
Debt Activity, Net
During the first six months of 2014, we decreased our net debt borrowings $1.1 billion. The decrease was the net impact of repaying our $500 million senior notes upon maturity, reducing commercial paper balances $862 million primarily with repatriated Canadian divestiture proceeds and EnLink borrowings of $235 million.
During the first six months of 2013, we repatriated $2.0 billion of foreign earnings to the U.S. and repaid outstanding commercial paper borrowings. The repayment resulted in a net repayment of $1.5 billion in the first six months of 2013.
Distributions to Devon shareholders
The following table summarizes our common stock dividends (amounts in millions) during the first six months of 2014 and 2013. In the second quarter of 2014, we increased our quarterly dividend to $0.24 per share.
Six Months Ended June 30, | ||||||||||||||||
2014 | 2013 | |||||||||||||||
Amount | Per Share | Amount | Per Share | |||||||||||||
Dividends |
$ | 189 | $ | 0.46 | $ | 170 | $ | 0.42 |
Distributions to noncontrolling interests
In conjunction with the formation of EnLink in the first quarter of 2014, we made a payment of $100 million to noncontrolling interests. Further, EnLink distributed $41 million to its non-Devon unitholders during the first six months of 2014.
Liquidity
Historically, our primary sources of capital and liquidity have been our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow and cash balances. Other available sources of capital and liquidity include debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC. We estimate the combination of these sources of capital will continue to be adequate to fund future capital expenditures, debt repayments and other contractual commitments. The following sections discuss changes to our liquidity subsequent to filing our 2013 Annual Report on Form 10-K.
Operating Cash Flow
Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, gas and NGLs we produce. We expect operating cash flow to continue to be our primary source of liquidity. To mitigate some of the risk inherent in prices, we have utilized various derivative financial instruments to set minimum and maximum prices on a portion of our 2014 production. The key terms to our open oil, gas and NGL derivative financial instruments as of June 30, 2014 are presented in Part I. Financial Information Item 1. Financial Statements Note 3 in this report.
Credit Availability
As of June 30, 2014, we had $3.0 billion of available capacity under our syndicated, unsecured revolving line of credit (the Senior Credit Facility), net of letters of credit outstanding. We also have access to $3.0 billion of short-term credit under our commercial paper program. At June 30, 2014, we had $0.5 billion of commercial paper borrowings outstanding.
38
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, to be no greater than 65 percent. As of June 30, 2014, we were in compliance with this covenant with a debt-to-capitalization ratio of 23.4 percent.
The Partnership has a $1.0 billion unsecured revolving credit facility, which includes a $500 million letter of credit subfacility. EnLink also has a $250 million revolving credit facility, which includes a $125 million letter of credit subfacility, as well as an additional credit agreement in association with E2 Energy Services LLC under which EnLink can borrow up to $20 million. On April 9, 2014, the E2 credit agreement was amended to increase the borrowing capacity to $30.0 million. As of June 30, 2014, there was $160 million borrowed under the $1.0 billion credit facility, and there was $95 million borrowed under the $250 million credit facility and $23 million borrowed in association with the E2 Energy Services LLC credit facility.
Asset Divestitures
In the second quarter of 2014, we reached an agreement to sell our U.S. non-core assets for $2.3 billion to Linn Energy. This transaction is expected to close in the third quarter of 2014.
Contractual Obligations
A summary of our contractual obligations as of June 30, 2014, is provided in the following table.
Payments Due by Period | ||||||||||||||||||||
Total |
Less Than 1
Year |
1-3 Years | 3-5 Years |
More Than 5
Years |
||||||||||||||||
(In millions) | ||||||||||||||||||||
Debt (1) |
$ | 12,357 | $ | 475 | $ | 2,750 | $ | 2,254 | $ | 6,878 | ||||||||||
Interest expense (2) |
7,895 | 523 | 1,021 | 923 | 5,428 | |||||||||||||||
Purchase obligations (3) |
5,973 | 438 | 1,781 | 1,756 | 1,998 | |||||||||||||||
Operational agreements (4) |
5,528 | 634 | 1,783 | 1,706 | 1,405 | |||||||||||||||
Asset retirement obligations (5) |
1,632 | 56 | 132 | 113 | 1,331 | |||||||||||||||
Drilling and facility obligations (6) |
189 | 163 | 18 | 2 | 6 | |||||||||||||||
Lease obligations (7) |
269 | 25 | 72 | 61 | 111 | |||||||||||||||
Other (8) |
353 | 183 | 72 | 45 | 53 | |||||||||||||||
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|
|
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Total |
$ | 34,196 | $ | 2,497 | $ | 7,629 | $ | 6,860 | $ | 17,210 | ||||||||||
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(1) | Debt amounts represent scheduled maturities of our debt obligations at June 30, 2014, excluding $2 million of net discounts included in the carrying value of debt. |
(2) | Interest expense represents the scheduled obligations on long-term, fixed-rate debt and an estimate of our floating-rate debt. |
(3) | Purchase obligation amounts represent contractual commitments primarily to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because condensate is an integral part of the heavy oil transportation process. Any disruption in our ability to obtain condensate could negatively affect our ability to transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. The value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices. |
(4) | Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream markets. Operational agreements include approximately $2.1 billion of obligations between Devon and EnLink. The terms of the contracts with EnLink are summarized in the following table. |
39
Minimum | Minimum | Minimum | ||||||||||||||||||
Gathering | Processing | Volume | ||||||||||||||||||
Contract | Volume | Volume | Commitment | Annual | ||||||||||||||||
Terms | Commitment | Commitment | Term | Rate | ||||||||||||||||
Contract |
(Years) | (MMcf/d) | (MMcf/d) | (Years) | Escalators | |||||||||||||||
Bridgeport gathering and processing contract |
10 | 850 | 650 | 5 | CPI | |||||||||||||||
East Johnson County gathering contract |
10 | 125 | | 5 | CPI | |||||||||||||||
Northridge gathering and processing contract |
10 | 40 | 40 | 5 | CPI | |||||||||||||||
Cana gathering and processing contract |
10 | 330 | 330 | 5 | CPI |
(5) | Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. |
(6) | Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. |
(7) | Lease obligations consist primarily of non-cancelable leases for office space and equipment used in our daily operations. |
(8) | These amounts include $221 million related to uncertain tax positions. |
Critical Accounting Estimates
Devon conducts its annual goodwill impairment test as of October 31 each year. At October 31, 2013, the date of our last goodwill impairment test, the fair values of our U.S. and Canadian reporting units exceeded their related carrying values. The fair value of our U.S. reporting unit substantially exceeded its carrying value. However, the fair value of our Canadian reporting unit is not substantially in excess of its carrying value. As of October 31, 2013, the fair value of our Canadian reporting unit exceeded its carrying value by approximately 11 percent. As of June 30, 2014, we had $2.1 billion of goodwill allocated to the Canadian reporting unit. Significant decreases to our stock price, decreases in commodity prices, negative deviations from projected Canadian reporting unit earnings or unfavorable changes in reserves could result in a goodwill impairment charge. A goodwill impairment charge would have no effect on liquidity or capital resources. However, it would adversely affect our results of operations in that period.
Non-GAAP Measures
We make reference to adjusted earnings attributable to Devon and adjusted earnings per share attributable to Devon in Overview of 2014 Results in this Item 2 that are not required by or presented in accordance with GAAP. These non-GAAP measures should not be considered as alternatives to GAAP measures. Adjusted earnings attributable to Devon, as well as the per share amount, represent net earnings excluding certain non-cash or non-recurring items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Items may appear to be recurring while comparing on an annual basis. In the below table, restructuring costs were incurred in each period. However, these costs relate to different restructuring programs. Amounts excluded for the first six months of 2014 relate to our Canadian divestiture program and amounts excluded for the first six months of 2013 relate to our office consolidation. For more information on our restructuring programs see Note 6 to the financial statements included in this report. We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
Adjusted Earnings and Adjusted Earnings Per Share Attributable to Devon
Below are reconciliations of our adjusted earnings and earnings per share attributable to Devon to their comparable GAAP measures.
Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
(In millions, except per share amounts) | ||||||||||||||||
Net earnings (loss) attributable to Devon (GAAP) |
$ | 675 | $ | 683 | $ | 999 | $ | (656 | ) | |||||||
Adjustments (net of taxes): |
||||||||||||||||
Derivatives and other financial instruments |
249 | (240 | ) | 453 | (27 | ) | ||||||||||
Cash settlements on derivatives and financial instruments |
(68 | ) | 12 | (132 | ) | 76 | ||||||||||
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|||||||||
Net derivatives and financial instruments |
181 | (228 | ) | 321 | 49 | |||||||||||
Investment in EnLink deferred income tax |
| | 48 | |
40
Restructuring costs |
4 | 5 | 32 | 29 | ||||||||||||
Gain on asset sales and related repatriation |
(286 | ) | | (279 | ) | | ||||||||||
Asset impairments |
| 31 | | 1,339 | ||||||||||||
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|
|||||||||
Adjusted earnings attributable to Devon (Non-GAAP) |
$ | 574 | $ | 491 | $ | 1,121 | $ | 761 | ||||||||
|
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|
|||||||||
Earnings (loss) per share (GAAP) |
$ | 1.64 | $ | 1.68 | $ | 2.44 | $ | (1.63 | ) | |||||||
Adjustments (net of taxes): |
||||||||||||||||
Derivatives and other financial instruments |
0.62 | (0.58 | ) | 1.10 | (0.07 | ) | ||||||||||
Cash settlements on derivatives and financial instruments |
(0.17 | ) | 0.03 | (0.32 | ) | 0.19 | ||||||||||
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|
|||||||||
Net derivatives and financial instruments |
0.45 | (0.55 | ) | 0.78 | 0.12 | |||||||||||
Investment in EnLink taxes |
| | 0.12 | | ||||||||||||
Restructuring costs |
0.01 | 0.01 | 0.08 | 0.07 | ||||||||||||
Gain on asset sales and related repatriation |
(0.70 | ) | | (0.68 | ) | | ||||||||||
Asset impairments |
| 0.07 | | 3.31 | ||||||||||||
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|
|||||||||
Adjusted earnings per share (Non-GAAP) |
$ | 1.40 | $ | 1.21 | $ | 2.74 | $ | 1.87 | ||||||||
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41
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
We have commodity derivatives that pertain to a portion of our production for the last six months of 2014, as well as 2015 and 2016. The key terms to our open oil, gas and NGL derivative financial instruments as of June 30, 2014 are presented in Part I. Financial Information Item 1. Financial Statements Note 3 in this report.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. At June 30, 2014, a 10 percent change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by the following amounts:
10% Increase | 10% Decrease | |||||||
(In millions) | ||||||||
Gain (loss): |
||||||||
Gas derivatives |
$ | (223 | ) | $ | 192 | |||
Oil derivatives |
$ | (727 | ) | $ | 645 |
Interest Rate Risk
At June 30, 2014, we had total debt outstanding of $12.4 billion. Of this amount, $10.8 billion bears fixed interest rates averaging 4.8 percent. The remaining $1.6 billion of debt is comprised of commercial paper borrowings that bear interest rates averaging 0.24 percent and floating rate debt that at June 30, 2014 had rates averaging 1.3 percent. Our commercial paper borrowings typically have maturities between 1 and 90 days.
As of June 30, 2014, we had open interest rate swap positions that are presented in Part I. Financial Information Item 1. Financial Statements Note 3 in this report. The fair values of our interest rate swaps are largely determined by estimates of the forward curves of the 3 month LIBOR rate. A 10 percent change in these forward curves would not have materially impacted our balance sheet at June 30, 2014.
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 an 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 June 30, 2014 balance sheet.
Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, one of these foreign subsidiaries holds Canadian-dollar cash and engages in short-term intercompany loans with Canadian subsidiaries that are based in Canadian dollars. The value of the Canadian-dollar cash and intercompany loans increases or decreases from the remeasurement of the cash and loans into the U.S. dollar functional currency. Additionally, at June 30, 2014, we held foreign currency exchange forward contracts to hedge exposures to fluctuations in exchange rates on the Canadian-dollar cash and intercompany loans. The increase or decrease in the value of the forward contracts is offset by the increase or decrease to the U.S. dollar equivalent of the Canadian-dollar cash and intercompany loans. Based on the amount of the cash and intercompany loans as of June 30, 2014, a 10 percent change in the foreign currency exchange rates would not have materially impacted our balance sheet.
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.
42
Based on their evaluation, our principal executive and principal financial officers have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of June 30, 2014, 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 were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
43
There have been no material changes to the information included in Item 3. Legal Proceedings in our 2013 Annual Report on Form 10-K.
There have been no material changes to the information included in Item 1A. Risk Factors in our 2013 Annual Report on Form 10-K.
Item 2 . Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information regarding purchases of our common stock that were made by us during the second quarter of 2014.
Period |
Total Number
of Shares Purchased (1) |
Average Price
Paid per Share |
||||||
April 1 April 30 |
20,756 | $ | 69.22 | |||||
May 1 May 31 |
7,844 | $ | 72.29 | |||||
June 1 June 30 |
3,820 | $ | 77.95 | |||||
|
|
|||||||
Total |
32,420 | $ | 70.99 | |||||
|
|
(1) | Share repurchases represent shares received by us from employees and directors for the payment of personal income tax withholding on restricted stock vesting and stock option exercises. |
Under the Devon Energy Corporation Incentive Savings Plan (the Plan), eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund (the Stock Fund), which is administered by an independent trustee. Eligible employees purchased approximately 12,300 shares of our common stock in the second quarter of 2014, at then-prevailing stock prices, that they held through their ownership in the Stock Fund. We acquired the shares of our common stock sold under the Plan through open-market purchases.
Similarly, under the Devon Canada Corporation Savings Plan (the Canadian Plan), eligible Canadian employees may purchase shares of our common stock through an investment in the Canadian Plan, which is administered by an independent trustee, Sun Life Assurance Company of Canada. We acquired the shares sold under the Canadian Plan through open-market purchases. These shares and any interest in the Canadian Plan were offered and sold in reliance on the exemptions for offers and sales of securities made outside of the U.S., including under Regulation S for offers and sales of securities to employees pursuant to an employee benefit plan established and administered in accordance with the law of a country other than the U.S. In the second quarter of 2014, there were no shares purchased by Canadian employees.
Item 3. Defaults Upon Senior Securities
Not applicable.
Item 4. Mine Safety Disclosures
Not applicable.
Not applicable.
44
(a) Exhibits required by Item 601 of Regulation S-K are as follows:
Exhibit Number |
Description |
|
10.1 | Devon Energy Corporation Non-Qualified Deferred Compensation Plan, Amended and Restated effective as of April 15, 2014. | |
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 |
45
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DEVON ENERGY CORPORATION | ||||||
Date: August 6, 2014 | /s/ Jeremy D. Humphers | |||||
Jeremy D. Humphers | ||||||
Senior Vice President and Chief Accounting Officer |
46
INDEX TO EXHIBITS
Exhibit Number |
Description |
|
10.1 | Devon Energy Corporation Non-Qualified Deferred Compensation Plan, Amended and Restated effective as of April 15, 2014. | |
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 |
47
Exhibit 10.1
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
Amended and Restated Effective as of April 15, 2014
TABLE OF CONTENTS
Page | ||||||
ARTICLE I ESTABLISHMENT AND PURPOSE |
1 | |||||
1.1 |
Establishment | 1 | ||||
1.2 |
Purpose | 1 | ||||
1.3 |
ERISA Status | 1 | ||||
ARTICLE II DEFINITIONS |
1 | |||||
2.1 |
Definitions | 1 | ||||
2.2 |
Construction | 5 | ||||
2.3 |
Funding | 5 | ||||
ARTICLE III ELIGIBILITY AND PARTICIPATION |
5 | |||||
3.1 |
Eligibility and Participation | 5 | ||||
ARTICLE IV ELECTIVE DEFERRALS |
5 | |||||
4.1 |
Deferrals | 5 | ||||
4.2 |
Timing of Deferral Election | 6 | ||||
4.3 |
Election Forms | 6 | ||||
4.4 |
Hardship Withdrawal Under Qualified Plan | 7 | ||||
ARTICLE V SUPPLEMENTAL COMPANY CONTRIBUTIONS |
7 | |||||
5.1 |
Supplemental Company Contributions | 7 | ||||
ARTICLE VI PAYMENT OF BENEFITS |
8 | |||||
6.1 |
Payment Events | 8 | ||||
6.2 |
Method of Payment Upon Separation from Service | 8 | ||||
6.3 |
Method of Payment Upon a Change of Control Payment Event | 8 | ||||
6.4 |
Method of Payment Upon Death | 9 | ||||
6.5 |
Payment Upon Scheduled In-Service Withdrawal | 9 | ||||
6.6 |
Payment to Specified Employees Upon Separation from Service | 9 | ||||
6.7 |
Changes in Method of Payment | 10 | ||||
6.8 |
Beneficiary Designations | 10 | ||||
6.9 |
Small Account Balances | 10 | ||||
6.10 |
Transition Exceptions | 10 | ||||
ARTICLE VII ACCOUNTS AND INVESTMENT |
10 | |||||
7.1 |
Participant Accounts | 10 | ||||
7.2 |
Adjustment of Accounts | 11 | ||||
7.3 |
Investment of Account | 11 | ||||
7.4 |
Vesting | 11 | ||||
7.5 |
Account Statements | 12 | ||||
ARTICLE VIII ADMINISTRATION |
12 | |||||
8.1 |
Administration | 12 | ||||
8.2 |
Indemnification and Exculpation | 12 |
-i-
TABLE OF CONTENTS
(continued)
Page | ||||||
8.3 |
Rules of Conduct | 12 | ||||
8.4 |
Legal, Accounting, Clerical and Other Services | 12 | ||||
8.5 |
Records of Administration | 12 | ||||
8.6 |
Expenses | 12 | ||||
8.7 |
Liability | 12 | ||||
8.8 |
Claims Review Procedures | 13 | ||||
8.9 |
Finality of Determinations; Exhaustion of Remedies | 14 | ||||
8.10 |
Effect of Committee Action | 14 | ||||
ARTICLE IX GENERAL PROVISIONS |
15 | |||||
9.1 |
Effect on Other Plans | 15 | ||||
9.2 |
Conditions of Employment Not Affected by Plan | 15 | ||||
9.3 |
Restrictions on Alienation of Benefits | 15 | ||||
9.4 |
Domestic Relations Orders | 15 | ||||
9.5 |
Information Required of Participants | 15 | ||||
9.6 |
Tax Consequences Not Guaranteed | 16 | ||||
9.7 |
Benefits Payable to Incompetents | 16 | ||||
9.8 |
Severability | 16 | ||||
9.9 |
Compliance with Section 409A | 16 | ||||
9.10 |
Tax Withholding | 16 | ||||
ARTICLE X AMENDMENT AND TERMINATION |
16 | |||||
10.1 |
Amendment and/or Termination | 16 | ||||
ARTICLE XI MISCELLANEOUS PROVISIONS |
17 | |||||
11.1 |
Articles and Section Titles and Headings | 17 | ||||
11.2 |
Joint Obligations | 17 | ||||
11.3 |
Governing Law | 17 |
-ii-
DEVON ENERGY CORPORATION
NON-QUALIFIED DEFERRED COMPENSATION PLAN
ARTICLE I
ESTABLISHMENT AND PURPOSE
1.1 Establishment . Devon Energy Corporation, a Delaware corporation ( Company ), established the Devon Energy Corporation Non-Qualified Deferred Compensation Plan effective October 1, 2001 (the Plan ). The Company hereby amends and restates the Plan effective April 15, 2014 (the Effective Date ). This amendment and restatement only applies to the amounts deferred under the Plan on or after January 1, 2005, and to amounts deferred prior to January 1, 2005 that were not vested as of December 31, 2004. Amounts deferred under the Plan prior to January 1, 2005 that were vested as of December 31, 2004 (the Grandfathered Amounts ) shall be subject to the provisions of the Plan as in effect on October 3, 2004. It is intended that the Grandfathered Amounts are to remain exempt from the requirements of Section 409A of the Code.
1.2 Purpose . The Plan shall provide Eligible Employees the ability to defer payment of Base Salary and Bonus. The Plan is also intended to provide the amount of the benefit which could otherwise be earned under the Devon Energy Corporation Incentive Savings Plan (the Qualified Plan ) but which cannot be contributed due to the limitations imposed by (i) Section 401(a)(17) of the Code, which limits the annual compensation that may be taken into account in computing benefits under plans qualified under Sections 401(a) and 501(a) of the Code and (ii) Sections 401(k) and 402(g) of the Code which limit benefits that may be contributed by the Company as a matching contribution under Section 401(m) of the Code (collectively referred to as the IRS Limitations ).
1.3 ERISA Status . The Plan is intended to qualify for the exemptions provided under Title I of ERISA for plans that are not tax-qualified and that are maintained primarily to provide deferred compensation for a select group of management or highly compensated employees as defined in Section 201(2) of ERISA.
ARTICLE II
DEFINITIONS
2.1 Definitions . For purposes of this Plan, the following definitions shall apply:
(a) Account means the recordkeeping accounts maintained by the Company to record the payment obligation of the Company to a Participant as determined under the terms of this Plan. The Company may maintain an Account to record the total obligation to the Participant under this Plan and component accounts to reflect amounts payable at different times and in different forms. Reference to an Account means any such Account established by the Company as the context requires.
(b) Affiliate means a corporation, trade or business that, together with the Company, is treated as a single employer under Section 414(b) or (c) of the Code.
(c) Applicable Contribution Percentage means the maximum matching contribution percentage the Participant is eligible to receive under the terms of the Qualified Plan for the Plan Year.
(d) Base Salary means the Participants annualized gross rate of base salary paid before any deductions of any kind whatsoever.
(e) Beneficiary means the person, persons, trust, or other entity designated by a Participant, on the beneficiary designation form adopted by the Committee, to receive benefits, if any, under this Plan at such Participants death pursuant to Section 6.4.
(f) Board means the Board of Directors of the Company.
(g) Bonus means the Participants cash bonus to be earned during each calendar year before any deductions of any kind whatsoever.
(h) Change of Control Payment Event shall mean, and shall be deemed to have occurred when, one of the events described in paragraphs (i), (ii), (iii), or (iv) below occurs. For the purpose of this subsection (h), the term Company shall mean Devon Energy Corporation and any successor thereto.
(i) The acquisition of stock of the Company by any one person, or more than one person acting as a group (as defined in §1.409A-3(i)(5)(v)(B) of the Treasury Regulations) (a Person ) that, together with stock held by such Person, constitutes more than 50% of either (I) the then outstanding shares of common stock of the Company or (II) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors; provided, however, that the following acquisitions shall not constitute a Change of Control Payment Event: (A) any acquisition by an underwriter temporarily holding securities pursuant to an offering of such securities; (B) any acquisition by the Company; (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company. If a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (i), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (i) by reason of subsequent changes in the holdings of such Person (except if the holdings of such Person are reduced to 50% or below and thereafter increase to more than 50%).
(ii) During a 12-month period, a majority of the individuals who, as of the Effective Date, constitute the Board (the Incumbent Board ) are replaced; provided, however, that any individual becoming a director subsequent to the Effective Date whose election, appointment or nomination for election by the Companys shareholders was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for purposes of this definition, any such individual whose initial assumption of office occurs as a result of an actual or publicly threatened election contest (as such terms are used in Rule 14a-11 promulgated under the Exchange Act) with respect to the election or removal of directors or other actual or publicly threatened solicitation of proxies or consents by or on behalf of a Person other than the Board.
2
(iii) The date a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of stock of the Company possessing 30% or more of the combined voting power of the then outstanding voting securities of the Company; provided that, if a Change of Control Payment Event occurs by reason of an acquisition described in this paragraph (iii), no additional Change of Control Payment Event shall be deemed to occur under this paragraph (iii) or paragraph (i) by reason of the acquisition of additional control of the Company by the same Person.
(iv) Approval by the shareholders of the Company of the sale or other disposition of all or substantially all of the assets of the Company to a Person, provided that, a transfer of the Companys assets shall not be treated as a Change of Control Payment Event if the assets are transferred to:
(1) A shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;
(2) An entity, 50% or more of the total value or voting power of which is owned, directly or indirectly, by the Company;
(3) A Person that owns, directly or indirectly, 50% or more of the total value or voting power of all the outstanding stock of the Company; or
(4) An entity, at least 50% of the total value or voting power of which is owned, directly or indirectly by a Person described in subparagraph (3).
Except as otherwise provided in this paragraph (iv), a Persons status is determined immediately after the transfer of the assets.
(i) Code means the Internal Revenue Code of 1986, as amended, and any regulations relating thereto.
(j) Committee means the Compensation Committee of the Board of Directors of the Company or a committee established by the Compensation Committee that has been delegated duties related to the Plan.
(k) Credited Earnings means the gains or losses applied to a Participants Account pursuant to Section 7.2.
(l) Deferred Amount means the portion of a Participants Base Salary or Bonus which the Participant elects to defer pursuant to Article IV, Deferred Amounts shall be determined by reference to the Plan Year in which the amount was deferred by the Participant.
(m) Disabled or Disability means the Participant is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or last for a continuous period of not less than 12 months. The Committee shall determine whether a Participant is Disabled in accordance with Section 409A of the Code.
3
(n) ERISA means the Employee Retirement Income Security Act of 1974, as amended.
(o) Eligible Employee means an employee who (i) is designated by the Committee as belonging to a select group of management or highly compensated employees, as such phrase is defined under ERISA; (ii) an executive of the Company or an Affiliate employed at a minimum salary level designated from time to time by the Committee; (iii) a resident of the United States; and (iv) paid on the Companys or its Affiliates United States payroll.
(p) Employer shall mean the Company and/or any Affiliate that employs a Participant in the Plan.
(q) Participant means an Eligible Employee who has Deferred Amounts and/or Supplemental Company Contributions credited to an Account under this Plan.
(r) Plan means this Devon Energy Non-Qualified Deferred Compensation Plan, as amended and restated effective as of the Effective Date.
(s) Plan-Approved Domestic Relations Order means a domestic relations order as defined in Section 414(p)(1)(B) of the Code that meets the requirements established by the Committee.
(t) Plan Year means the 12-month period beginning on January 1 and ending on December 31.
(u) Qualified Plan means the Devon Energy Corporation Incentive Savings Plan or any successor plan thereto.
(v) Separation from Service means termination of employment with the Employer under the circumstances described below. Whether a Separation from Service has occurred shall be determined by the Committee in accordance with Section 409A of the Code.
Except in the case of a Participant on a bona fide leave of absence as provided below, a Participant is deemed to have incurred a Separation from Service if the Employer and the Participant reasonably anticipated that the level of services to be performed by the Participant after a certain date would be permanently reduced to 20% or less of the average services rendered by the Participant during the immediately preceding 36-month period (or the total period of employment, if less than 36 months), disregarding periods during which the Participant was on a bona fide leave of absence.
A Participant who is absent from work due to military leave, sick leave, or other bona fide leave of absence shall incur a Separation from Service on the first date immediately following the later of (i) the six-month anniversary of the commencement of the leave or (ii) the expiration of the Participants right, if any, to reemployment under statute or contract.
For purposes of determining whether a Separation from Service has occurred, the Employer means the Employer as defined in Section 2.1(p), except that for purposes of determining whether another organization is an Affiliate of the Company, common ownership of at least 50% shall be determinative.
4
(w) Specified Employee means those employees of the Company who are determined by the Committee to be a specified employee in accordance with Section 409A of the Code and the Devon Energy Corporation Specified Employee Policy.
(x) Supplemental Company Contribution means the contribution made by the Company for the benefit of a Participant under Article V in any Plan Year.
2.2 Construction . Except when otherwise indicated by the context, any masculine terminology when used in the Plan shall also include the feminine gender, and the definition of any term in the singular shall also include the plural.
2.3 Funding . The benefits described in this Plan are contractual obligations of the Employers to pay compensation for services, and shall constitute a liability to the Participants and/or their Beneficiaries in accordance with the terms hereof. All amounts paid under this Plan shall be paid in cash from the general assets of the Employers and shall be subject to the general creditors of the Company and the Employer of the Participant. Benefits shall be reflected on the accounting records of the Employers but shall not be construed to create, or require the creation of, a trust, custodial or escrow account. No special or separate fund need be established and no segregation of assets need be made to assure the payment of such benefits. No Participant shall have any right, title or interest whatever in or to any investment reserves, accounts, funds or assets that the Employer may purchase, establish or accumulate to aid in providing the benefits described in this Plan. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust or a fiduciary relationship of any kind between an Employer or the Company and a Participant or any other person; provided, however, that the Company may establish and/or continue a grantor trust as defined in Section 671 of the Code to provide a source of funding for amounts deferred hereunder. Neither a Participant nor the Beneficiary of a Participant shall acquire any interest hereunder greater than that of an unsecured creditor of the Company or any Affiliate who is the Employer of such Participant.
ARTICLE III
ELIGIBILITY AND PARTICIPATION
3.1 Eligibility and Participation . The Committee shall provide employees selected for participation in this Plan with notice of the employees selection as an Eligible Employee under this Plan for the applicable Plan Year and permit such Eligible Employee the opportunity to make an election pursuant to Article IV. Such notice may be given at such time and in such manner as the Committee may determine. All determinations as to whether an employee is eligible to make deferral elections shall be made by the Committee. The determinations of the Committee shall be final and binding on all employees.
ARTICLE IV
ELECTIVE DEFERRALS
4.1 Deferrals . Elective deferrals may be made with respect to the following sources in accordance with the provisions of Article IV:
5
(a) Bonus . An Eligible Employee may elect to defer up to 100% of the Eligible Employees Bonus as long as such deferral does not reduce such Eligible Employees Bonus below an amount necessary to satisfy applicable tax withholding obligations, benefit plan contributions, and other withholding obligations. The amount deferred shall be specified as a percentage or dollar amount of any Bonus which may be earned by an Eligible Employee in the applicable Plan Year
(b) Base Salary . An Eligible Employee may elect to defer up to 50% of the Eligible Employees Base Salary as long as such deferral does not reduce such Eligible Employees Base Salary below an amount necessary to satisfy applicable tax withholding obligations, benefit plan contributions, and other withholding obligations. The amount deferred shall be specified as a percentage or dollar amount of any Base Salary which may be earned by an Eligible Employee in the applicable Plan Year.
Notwithstanding the foregoing, the deferral election of any Eligible Employee who initially becomes eligible to participate in the Plan during a Plan Year pursuant to Section 4.2(b) shall apply only to Base Salary and any Bonus which may be earned by such Eligible Employee with respect to services performed after the Eligible Employee files an irrevocable deferral election form and it is effective. In this regard, an Eligible Employees Bonus deferral election shall be prorated to the extent necessary to ensure that it applies only to the portion of the Bonus earned for periods after the deferral election is filed and effective.
4.2 Timing of Deferral Election . The timing of deferral elections shall be as follows:
(a) Except as otherwise provided in subsection (b) with respect to an Eligible Employees initial year of eligibility (if such Eligible Employee is designated by the Committee as initially being eligible to commence participation in the Plan during such initial year of eligibility), an Eligible Employee must file a deferral election form for each Plan Year and the Eligible Employees election to defer Base Salary or Bonus shall apply to Base Salary or Bonus earned for services rendered during the Plan Year that commences immediately following the Plan Year in which the election is made and is irrevocable except as otherwise provided herein. Irrevocable elections to defer Base Salary or Bonus must be completed and filed on or before December 31 of the year immediately preceding the Plan Year in which the services related to the compensation to be deferred are rendered.
(b) For any Eligible Employee who is designated by the Committee as initially being eligible to commence participation in the Plan during a particular Plan Year, the Eligible Employee must file an irrevocable deferral election to defer Base Salary or Bonus earned with respect to services performed after the date on which the deferral election is filed and effective except as otherwise provided herein. A deferral election may not be effective any earlier than the date it is filed. Irrevocable elections to defer Base Salary or Bonus for the remainder of the Plan Year of initial eligibility must be completed and filed within 30 days after the date on which the Eligible Employee becomes initially eligible to participate in the Plan and shall apply to Base Salary or Bonus only as described in Section 4.1.
4.3 Election Forms . All elections to defer shall be made on a deferral election form. In addition to the deferral election form, a Participant may be required by the Committee to complete additional forms such that they have adequate information concerning the Deferred Amount, timing of distributions and the form of payment, if applicable.
6
4.4 Hardship Withdrawal Under Qualified Plan . If a Participant makes a hardship withdrawal under the Qualified Plan and such Participant is prohibited (including, without limitation, temporarily suspended) from making future contributions under such Qualified Plan (and this Plan) by the terms of such qualified retirement plan, then, deferrals by the Participant under this Plan shall be automatically cancelled for the remainder of the Plan Year.
ARTICLE V
SUPPLEMENTAL COMPANY CONTRIBUTIONS
5.1 Supplemental Company Contributions . For each calendar quarter of the Plan Year (i.e., the quarters ending March 31, June 30, September 30 and December 31), the Company will credit to the Account of each Participant a Supplemental Company Contribution in an amount equal to (a) minus (b) minus (c) below:
(a) The Applicable Contribution Percentage multiplied by the Participants Base Salary and Bonus for the Plan Year up through the applicable calendar quarter.
(b) The Applicable Contribution Percentage multiplied by such Participants eligible 401(k) compensation for the Plan Year up through the applicable calendar quarter, which, for purposes of this Article V, shall be defined as the Participants Base Salary and Bonus less the Participants Deferred Amount (each for the Plan Year up through the applicable calendar quarter) up to the IRS Limitations for the applicable Plan Year.
(c) The Supplemental Company Contribution, if any, previously credited to the Account of the Participant for the Plan Year.
Provided, however, that, notwithstanding anything in this Section 5.1 to the contrary, the Supplemental Company Contribution cannot exceed the Participants Deferred Amount for the applicable Plan Year; provided further that the Supplemental Company Contribution will only be credited to the Account of a Participant for any calendar quarter of the Plan Year if as of the last day of the applicable calendar quarter of the Plan: (i) such Participant has made the maximum deferral of compensation as permitted under Sections 402(g) and 414(v) of the Code to the Qualified Plan (or, if less, the maximum deferral of compensation as permitted under the terms of the Qualified Plan); (ii) the Company has made the maximum matching contribution to the Qualified Plan as permitted under Section 401(m) of the Code and the Qualified Plan and (iii) such Participant is an Eligible Employee.
Notwithstanding the foregoing, for the Plan Year beginning January 1, 2013, the Company shall make a Supplemental Company Contribution for the six-month period beginning January 1, 2013 and ending June 30, 2013 (and the Company shall not be required to make a Supplemental Company Contribution for the calendar quarter ending March 31, 2013); provided, however, that the Participant otherwise satisfies all requirements set forth in this Section 5.1 and the Participant is an Eligible Employee on June 30, 2013.
7
Notwithstanding the forgoing, a Participant who is a Transferring Employee (as defined below) shall continue to be eligible to receive a Supplemental Company Contribution for the quarter in which he becomes an employee of EnLink Midstream Operating, LP even though such Participant is not an Eligible Employee on the last day of such applicable calendar quarter of the Plan Year. For purposes of this Plan (i) a Transferring Employee shall mean a Participant whose employment with the Company or any subsidiary is transferred to EnLink Midstream Operating, LP as of the Transfer Date, and (ii) the Transfer Date shall mean March 7, 2014, or such later date as of the occurrence of the Closing of the Mergers as defined under the Agreement and Plan of Merger by and among Devon Energy Corporation, Devon Gas Services, L.P., Acacia Natural Gas Corp I, Inc., Crosstex Energy, Inc., New Public Rangers, L.L.C., Boomer Merger Sub, Inc. and Rangers Merger Sub, Inc., dated October 21, 2013.
ARTICLE VI
PAYMENT OF BENEFITS
6.1 Payment Events . Unless otherwise distributed in accordance with the terms of a Scheduled In-Service Withdrawal, a Participants Account shall become payable at the time and in the form described in this Article upon the earlier to occur of the following events: (i) a Participants Separation from Service; (ii) a Participants Disability; (iii) a Change of Control Payment Event or (iv) the Participants death.
6.2 Method of Payment Upon Separation from Service . A Participant must specify on the deferral election form for each Plan Year the method of payment of the portion of Participants Account attributable to such Plan Year. A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of one or more years as made available to the Participant on the deferral election form provided for such purpose. Installment payments shall be paid quarterly, with the first installment paid within 90 days following the Participants Separation from Service, unless the Participant is a Specified Employee, or in the case of Disability, within 90 days of the date the Participant is Disabled and each subsequent installment paid on a quarterly basis until all installment payments have been paid. If the Participant (i) fails to make an effective designation as to the method of payment or (ii) elects to receive payment in the form of a lump sum, payment shall be automatically made in the form of a single lump sum payment within 90 days following the Participants Separation from Service, unless the Participant is a Specified Employee, or in the case of Disability, within 90 days of the date the Participant was Disabled. In the event the Participant is a Specified Employee, payment shall be postponed for a period of six months following Separation from Service and shall commence within 90 days of the first business day of the seventh month following Separation from Service.
6.3 Method of Payment Upon a Change of Control Payment Event . Plan Account balances will be paid within 90 days of the occurrence of a Change of Control Payment Event. A Participant may designate payment in the form of a single lump sum payment or quarterly installment payments payable over a period of one or more years as made available to the Participant on the deferral election form provided for such purpose, such designation to be made on the election form that is submitted for such Plan Year in accordance with Section 4.2. If the Participant fails to make an effective designation as to the method of payment, payment will be made in the form of a lump sum.
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6.4 Method of Payment Upon Death . If a Participant dies with a balance credited to the Participants Account, such balance shall be paid to the Participants Beneficiary. If the Participant dies prior to the time of payment of the Account, the then current balance of each of the Participants Account or subaccount shall be paid to the Participants Beneficiary in a lump sum commencing within 90 days of the date of Participants death. If payment of Participants Account has commenced as of the date of Participants death, the then current balance of each Account or subaccount payable to a Beneficiary shall be paid under the method designated for the payment of such amount by the Participant commencing within 90 days of the date of Participants death. Each Beneficiary of a deceased Participant who is eligible to receive payments under this Section shall have the amounts to be paid to such Beneficiary allocated to a subaccount in the name of the Beneficiary under the deceased Participants Account. Such subaccount shall be adjusted from time to time as provided in Article VII.
6.5 Payment Upon Scheduled In-Service Withdrawal . A Participant may schedule distribution of the Deferred Amounts and any Credited Earning attributable thereto attributable to a particular Plan Year ( Scheduled In-Service Withdrawal ) at least two years after the Plan Year in which deferrals were made. Participants must request a Scheduled In-Service Withdrawal, and a method of payment described in subsection (a) below, on the election form that is submitted in conjunction with the deferral election for such Plan Year. Except as provided in Section 6.10 below, if a Participant fails to elect a Scheduled In-Service Withdrawal for that Plan Year, a Participant will not be eligible to obtain a Scheduled In-Service Withdrawal for such Plan Year.
(a) The Participant may elect either a lump sum payment or quarterly installment payments payable over a period of one or more years as made available to the Participant on the deferral election form provided for such purpose. Payment will be made (or commence in the case of installments) within 30 days of the first business day of January in the year elected.
(b) A Participant may postpone payment of a Scheduled In-Service Withdrawal to a date at least five years later than the previously Scheduled In-Service Withdrawal date by filing a written request with the Committee at least twelve months prior to the date the Scheduled In-Service Withdrawal is scheduled to begin. Any request to postpone payment of a Scheduled In-Service Withdrawal will be irrevocable, except as may be permitted by the Code or applicable guidance promulgated thereunder.
(c) In the event of death, Disability, the occurrence of a Change of Control Payment Event or Separation from Service, payment of the Participants Account shall be determined without regard to the otherwise Scheduled In-Service Withdrawal which shall be deemed to be cancelled.
6.6 Payment to Specified Employees Upon Separation from Service . In no event shall a Specified Employee receive a payment under this Plan following a Separation from Service prior to the first business day of the seventh month following the date of Separation from Service.
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6.7 Changes in Method of Payment . The method of payment may be changed from time to time by the Participant, but in no event later than the date that is twelve months prior to the date payment would have otherwise commenced. Any requests to change the method of payment will not take effect for twelve months following the date it is received by the Committee and the first payment with respect to such election will be deferred for a period of at least five years from the date such payment would otherwise have commenced. Any request to change the method of payment will be irrevocable, except as may be permitted by the Code or applicable guidance promulgated thereunder.
6.8 Beneficiary Designations . A Participant shall designate on a beneficiary designation form a Beneficiary who, upon the Participants death, will receive payments that otherwise would have been paid to him under the Plan. All Beneficiary designations shall be in writing. Any such designation shall be effective only if and when delivered to the Committee during the lifetime of the Participant. A Participant may change a Beneficiary or Beneficiaries by filing a new beneficiary designation form. The latest beneficiary designation form shall apply to the combined Accounts and subaccounts of the Participant. If a Beneficiary of a Participant predeceases the Participant, the designation of such Beneficiary shall be void. If a Beneficiary to whom benefits under the Plan remain unpaid dies after the Participant and the Participant failed to specify a contingent Beneficiary on the appropriate beneficiary designation form, the remainder of such death benefit payments shall be paid to such Beneficiarys estate. If a Participant fails to designate a Beneficiary with respect to any death benefit payments or if such designation is ineffective, in whole or in part, any payment that otherwise would have been paid to such Participant shall be paid to the Participants estate.
6.9 Small Account Balances . If, upon Separation from Service, the value of the Participants Account is less than $10,000, the balance of such Account shall be paid in a single lump sum.
6.10 Transition Exceptions . Under the transition guidance issued by the Internal Revenue Service under Section 409A of the Code, an exception to the general timing rules shall apply to 2005, 2006, 2007 and 2008 Plan Year Account balances. Participants elections for the 2005, 2006, 2007 and 2008 Plan Years may be revised with respect to the timing and method of payment; provided, that such revised election (i) if made in the 2007 Plan Year, does not cause amounts that were otherwise payable in 2007 to be paid in a subsequent year, and does not provide for amounts payable in a subsequent year to be paid in 2007, and (ii) if made in the 2008 Plan Year, does not cause amounts that were otherwise payable in 2008 to be paid in a subsequent year, and does not provide for amounts payable in a subsequent year to be paid in 2008. The Committee will administer this provision to ensure compliance with IRS Notice 2006-79.
ARTICLE VII
ACCOUNTS AND INVESTMENT
7.1 Participant Accounts . The Committee shall maintain, or cause to be maintained, a bookkeeping Account for each Participant for the purpose of accounting for the Participants interest under the Plan. The Committee shall maintain within each Participants Account such subaccounts as may be necessary to identify each separate Deferred Amount, Supplemental
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Company Contribution and Credited Earnings attributable thereto, by reference to the Plan Year to which each Deferred Amount and Supplemental Company Contribution relates. The combination of the subaccounts maintained in the name of a Participant shall comprise the Participants Account.
7.2 Adjustment of Accounts . Each Participants Account shall be adjusted to reflect all Deferred Amounts and Supplemental Company Contributions credited to the Participants Account, all positive or negative Credited Earnings credited or debited to the Participants Account as provided by Section 7.3, and all benefit payments charged to the Participants Account. A Participants Deferred Amount shall be credited to such Participants Account as of the date on which the amount being deferred would have become payable to the Participant absent the election to defer, or on such other date as the Committee specifies, and shall be credited to the applicable subaccount within such Account by reference to the applicable Plan Year. Supplemental Company Contributions shall be credited to a Participants Account on such date or dates as the Committee specifies and shall be credited to the applicable subaccount within such Account by reference to the applicable Plan Year; provided, however, that under no circumstances shall Supplemental Company Contributions be credited to the Account of a Participant before such Participant has made the maximum deferral of compensation as permitted under Section 402(g) and 414(v) of the Code to the Qualified Plan (or, if less, the maximum deferral of compensation as permitted under the terms of the Qualified Plan), the Company has made the maximum matching contribution to the Qualified Plan as permitted under Section 401(m) of the Code and the Qualified Plan, and the Participant has otherwise satisfied the requirements set forth in Section 5.1 to receive a Supplement Company Contribution. Supplemental Company Contributions shall be subject to the vesting requirements described in Section 7.4.
7.3 Investment of Account . The Committee will offer Participants a selection of benchmark funds as deemed investment alternatives. The benchmark funds offered will be determined in the sole discretion of the Committee. Each Participant may select among the different benchmark funds offered. The deemed investments in benchmark funds are only for the purpose of determining the Companys payment obligation under the Plan. Credited Earnings shall be allocated to a Participants Account pursuant to the performance of the benchmark funds selected by the Participant. A Participant may, as frequently as daily, modify his election of benchmark funds through a procedure designated by the Committee. Such modification will be in accordance with rules and procedures adopted by the Committee.
7.4 Vesting . Subject to the conditions and limitations on payment of benefits under the Plan, a Participant shall always have a fully vested and nonforfeitable beneficial interest in the balance standing to the credit of the Participants Account attributable to Deferred Amounts and Credited Earnings attributable to the Deferred Amounts. A Participant shall become vested in Supplemental Company Contributions and Credited Earnings thereon as such Participant would be vested pursuant to the terms of the Qualified Plan. For the avoidance of doubt, a Participant who is a Transferring Employee (as defined in Section 5.1) shall become fully vested in any unvested Supplemental Company Contributions and Credited Earnings thereon effective as of the Transfer Date (as defined in Section 5.1).
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7.5 Account Statements . The Committee shall provide each Participant with a statement of the status of the Participants Account under the Plan. The Committee shall provide such statement annually or at such other times as the Committee may determine. Account statements shall be in the format prescribed by the Committee.
ARTICLE VIII
ADMINISTRATION
8.1 Administration . The Plan shall be administered, construed and interpreted by the Committee. The Committee shall have the sole authority and discretion to determine eligibility and to construe the terms of the Plan. The determinations by the Committee as to any disputed questions arising under the Plan, including the Eligible Employees who are eligible to be Participants in the Plan and the amounts of their benefits under the Plan, and the construction and interpretation by the Committee of any provision of the Plan, shall be final, conclusive and binding upon all persons including Participants, their beneficiaries, the Company, its stockholders and employees and the Employers. The Committee may, in its sole discretion, delegate its authority hereunder, including, but not limited to, delegating authority to modify, amend, administer, interpret, construe or vary the Plan, to the extent permitted by applicable law or administrative or regulatory rule, and, to the extent the Committee delegates its authority, applicable references herein to the Committee also shall mean the Committees delegate.
8.2 Indemnification and Exculpation . The members of the Committee and its agents shall be indemnified and held harmless by the Company against and from any and all loss, cost, liability or expense that may be imposed upon or reasonably incurred by them in connection with or resulting from any claim, action, suit or proceeding to which they may be a party or in which they may be involved by reason of any action taken or failure to act under this Plan and against and from any and all amounts paid by them in settlement (with the Companys written approval) or paid by them in satisfaction of a judgment in any such action, suit or proceeding. The foregoing provisions shall not be applicable to any person if the loss, cost, liability or expense is due to such persons gross negligence or willful misconduct.
8.3 Rules of Conduct . The Committee shall adopt such rules for the conduct of its business and the administration of this Plan as it considers desirable, provided they do not conflict with the provisions of this Plan.
8.4 Legal, Accounting, Clerical and Other Services . The Committee may authorize one or more if its members or any agent to act on its behalf and may contract for legal, accounting, clerical and other services to carry out this Plan. The Company shall pay all expenses of the Committee.
8.5 Records of Administration . The Committee shall keep records reflecting the administration of this Plan which shall be subject to audit by the Company.
8.6 Expenses . The expenses of administering the Plan shall be borne by the Company.
8.7 Liability . No member of the Board of Directors or of the Committee shall be liable for any act or action, whether of commission or omission, taken by any other member, or by any officer, agent, or employee of the Company or of any such body, nor, except in circumstances involving his bad faith, for anything done or omitted to be done by himself.
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8.8 Claims Review Procedures . The following claim procedures shall apply until such time as a Change of Control Payment Event has occurred. During the 24-month period following a Change of Control Payment Event, these procedures shall apply only to the extent the claimant requests their application. After the expiration of the 24-month period following a Change of Control Payment Event, then, these procedures shall again apply until the occurrence of a subsequent Change of Control Payment Event.
(a) Denial of Claim . If a claim for benefits is wholly or partially denied, the claimant shall be given notice in writing of the denial within a reasonable time after the receipt of the claim, but not later than 90 days after the receipt of the claim. However, if special circumstances require an extension, written notice of the extension shall be furnished to the claimant before the termination of the 90-day period. In no event shall the extension exceed a period of 90 days after the expiration of the initial 90-day period. The notice of the denial shall contain the following information written in a manner that may be understood by a claimant:
(i) The specific reasons for the denial;
(ii) Specific reference to pertinent Plan provisions on which the denial is based;
(iii) A description of any additional material or information necessary for the claimant to perfect his claim and an explanation of why such material or information is necessary;
(iv) An explanation that a full and fair review by the Committee of the denial may be requested by the claimant or his authorized representative by filing a written request for a review with the Committee within 60 days after the notice of the denial is received; and
(v) If a request for review is filed, the claimant or his authorized representative may review pertinent documents and submit issues and comments in writing within the 60-day period described in Section 8.8(a)(iv).
(b) Decisions After Review . The decision of the Committee with respect to the review of the denial shall be made promptly and in writing, but not later than 60 days after the Committee receives the request for the review. However, if special circumstances require an extension of time, a decision shall be rendered not later than 120 days after the receipt of the request for review. A written notice of the extension shall be furnished to the claimant prior to the expiration of the initial 60-day period. The claimant shall be given a copy of the decision, which shall state, in a manner calculated to be understood by the claimant, the specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based.
(c) Other Procedures . Notwithstanding the foregoing, the Committee may, in its discretion, adopt different procedures for different claims without being bound by past actions. Any procedures adopted, however, shall be designed to afford a claimant a full and fair review of his claim and shall comply with applicable regulations under ERISA.
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8.9 Finality of Determinations; Exhaustion of Remedies . To the extent permitted by law, decisions reached under the claims procedures set forth in Section 8.8 shall be final and binding on all parties. No legal action for benefits under the Plan shall be brought unless and until the claimant has exhausted his remedies under Section 8.8. In any such legal action, the claimant may only present evidence and theories which the claimant presented during the claims procedure. Any claims which the claimant does not in good faith pursue through the review stage of the procedure shall be treated as having been irrevocably waived. Judicial review of a claimants denied claim shall be limited to a determination of whether the denial was arbitrary, capricious or an abuse of discretion based on the evidence and theories the claimant presented during the claims procedure. This Section shall have no application during the 24-month period following a Change of Control Payment Event as to a claim which is first asserted or first denied after the Change of Control Payment Event and, as to such a claim, the de novo standard of judicial review shall apply. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.
8.10 Effect of Committee Action . The Plan shall be interpreted by the Committee in accordance with the terms of the Plan and their intended meanings. However, the Committee shall have the discretion to make any findings of fact needed in the administration of the Plan, and shall have the discretion to interpret or construe ambiguous, unclear or implied (but omitted) terms in any fashion they deem to be appropriate in their sole judgment. Except as stated in Section 8.9, the validity of any such finding of fact, interpretation, construction or decision shall not be given de novo review if challenged in court, by arbitration or in any other forum, and shall be upheld unless clearly arbitrary or capricious. To the extent the Committee has been granted discretionary authority under the Plan, the Committees prior exercise of such authority shall not obligate it to exercise its authority in a like fashion thereafter. If any Plan provision does not accurately reflect its intended meaning, as demonstrated by consistent interpretations or other evidence of intent, or as determined by the Committee in it sole and exclusive judgment, the provision shall be considered ambiguous and shall be interpreted by the Committee and all Plan fiduciaries in a fashion consistent with its intent, as determined by the Committee in its sole discretion. The Committee may amend the Plan retroactively to cure any such ambiguity. This Section may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Committee. All actions taken and all determinations made in good faith by the Committee shall be final and binding upon all persons claiming any interest in or under the Plan. This Section shall not apply to Committee actions or interpretations which take place or are made during the 24-month period following a Change of Control Payment Event. After the expiration of the 24-month period following a Change of Control Payment Event, then, this Section shall again apply until the occurrence of a subsequent Change of Control Payment Event.
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ARTICLE IX
GENERAL PROVISIONS
9.1 Effect on Other Plans . Deferred Amounts shall not be considered as part of a Participants compensation for the purpose of any qualified employee pension plans maintained by the Company or its Affiliates in the Plan Year in which any deferral occurs under this Plan, and such amounts will not be considered under the Companys Qualified Plan in the Plan Year in which payment occurs, but may be considered as covered compensation under the Companys qualified defined benefit pension plan entitled Retirement Plan for Employees of Devon Energy Corporation if permitted under the terms of such plan. However, such amounts may be taken into account under all other employee benefit plans maintained by the Company or its Affiliates in the year in which such amounts would have been payable absent the deferral election; provided, such amounts shall not be taken into account if their inclusion would jeopardize the tax-qualified status of the plan to which they relate.
9.2 Conditions of Employment Not Affected by Plan . The establishment and maintenance of the Plan shall not be construed as conferring any legal rights upon any Participant to the continuation of employment with the Company, nor shall the Plan interfere with the rights of the Company to discharge any Participant with or without cause.
9.3 Restrictions on Alienation of Benefits . No right or benefit under this Plan shall be subject to anticipation, alienation, sale, assignment, pledge, encumbrance, or charge, and any attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge the same shall be void. No right or benefit hereunder shall in any manner be liable for or subject to the debts, contracts, liabilities, or torts of the person entitled to such benefit. If any Participant or the Participants Beneficiary under this Plan should become bankrupt or attempt to anticipate, alienate, sell, assign, pledge, encumber, or charge any right to a benefit hereunder, then, such right or benefit shall cease and terminate. Notwithstanding the foregoing, in the event that all or any portion of the benefit of a Participant was transferred to the former spouse of the Participant incident to a divorce prior to January 1, 2013, the Committee shall maintain such amount for the benefit of the former spouse until distributed in the manner required by an order of any court having jurisdiction over the divorce, and the former spouse shall be entitled to the same rights as the Participant with respect to such benefit.
9.4 Domestic Relations Orders . Domestic relations orders purporting to assign a Participants benefits under the Plan constitute an impermissible alienation of benefits pursuant to Section 9.3 and shall not be honored by the Committee.
9.5 Information Required of Participants . Payment of benefits shall begin as of the payment date(s) provided in this Plan and no formal claim shall be required therefor; provided, in the interest of orderly administration of the Plan, the Committee may make reasonable requests of Participants and Beneficiaries to furnish information which is reasonably necessary and appropriate to the orderly administration of the Plan, and, to that limited extent, payments under the Plan are conditioned upon the Participants and Beneficiaries promptly furnishing true, full and complete information as the Committee may reasonably request.
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9.6 Tax Consequences Not Guaranteed . The Company does not warrant that this Plan will have any particular tax consequences for Participants or Beneficiaries and shall not be liable to them if tax consequences they anticipate do not actually occur. The Company shall have no obligation to indemnify a Participant or Beneficiary for lost tax benefits (or other damage or loss).
9.7 Benefits Payable to Incompetents . Any benefits payable hereunder to a minor or person under legal disability may be made, at the discretion of the Committee, (i) directly to the said person, or (ii) to a parent, spouse, relative by blood or marriage, or the legal representative of said person. The Committee shall not be required to see to the application of any such payment, and the payees receipt shall be a full and final discharge of the Committees responsibility hereunder.
9.8 Severability . If any provision of the Plan is held invalid or illegal for any reason, any illegality or invalidity shall not affect the remaining provisions of the Plan, and the Plan shall be construed and enforced as if the illegal or invalid provision had never been contained therein. The Company shall have the privilege and opportunity to correct and remedy such questions of illegality or invalidity by amendment.
9.9 Compliance with Section 409A . Notwithstanding anything in the Plan to the contrary, the terms of the Plan and all distributions made hereunder are intended to, and shall be interpreted and applied so as to, comply in all respects with the provisions of Section 409A of the Code and rulings promulgated thereunder and, if necessary, any provision shall be held null and void to the extent such provision (or part thereof) fails to comply with Section 409A of the Code and rulings promulgated thereunder. The Committee shall interpret the Plan consistent with the requirements of Section 409A of the Code, which shall govern the administration of the Plan in the event of any conflict between Plan terms and the applicable requirements of Section 409A of the Code and rulings promulgated thereunder. In any circumstance when a payment may be made in either of two calendar years, in no event may a Participant, directly or indirectly, designate the calendar year of such payment.
9.10 Tax Withholding . The Employer may withhold from a payment or accrued benefit or from the Participants other compensation any federal, state, or local taxes required by law to be withheld with respect to such payment or accrued benefit and such sums as the Employer may reasonably estimate as necessary to cover any taxes for which the Employer may be liable and which may be assessed with regard to such payment.
ARTICLE X
AMENDMENT AND TERMINATION
10.1 Amendment and/or Termination . The Committee may amend or modify the Plan at any time and in any manner; provided, however, that (i) no amendment shall reduce any portion of a Participants Account that is vested and (ii) no amendment shall be effective to the extent it results in a violation of Section 409A of the Code. The Committee may terminate the Plan within the parameters and limitations imposed by Section 409A of the Code.
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ARTICLE XI
MISCELLANEOUS PROVISIONS
11.1 Articles and Section Titles and Headings . The titles and headings at the beginning of each Article and Section shall not be considered in construing the meaning of any provisions in this Plan.
11.2 Joint Obligations . For purposes of this Plan, the Company and Devon Energy Company, L.P., an Oklahoma limited partnership, shall have joint and several liability for all obligations hereunder.
11.3 Governing Law . This Plan is subject to ERISA, but is exempt from most parts of ERISA since it is an unfunded deferred compensation plan maintained for a select group of management or highly compensated employees. In no event shall any references to ERISA in the Plan be construed to mean that the Plan is subject to any particular provisions of ERISA. The Plan shall be governed and construed in accordance with federal law and the laws of the State of Oklahoma, except to the extent such laws are preempted by ERISA.
* * * * * * * * *
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IN WITNESS WHEREOF, the Company has caused this instrument to be executed by its duly authorized officer.
DEVON ENERGY CORPORATION, a Delaware | ||
corporation | ||
By: |
/s/ Frank W. Rudolph |
|
Frank W. Rudolph, Executive Vice President - | ||
Human Resources |
[ Signature Page to Devon Energy Corporation Non-Qualified Deferred Compensation Plan ]
Exhibit 31.1
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John Richels, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Devon Energy Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: August 6, 2014
/s/ John Richels |
John Richels |
President and Chief Executive Officer |
Exhibit 31.2
CERTIFICATION PURSUANT TO
RULE 13a-14(a)/15d-14(a),
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Thomas L. Mitchell, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Devon Energy Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c) evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d) disclosed in this report any change in the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of registrants board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: August 6, 2014
/s/ Thomas L. Mitchell |
Thomas L. Mitchell |
Executive Vice President and Chief Financial Officer |
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Devon Energy Corporation (Devon) on Form 10-Q for the period ended June 30, 2014 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, John Richels, President and Chief Executive Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon. |
/s/ John Richels |
John Richels |
President and Chief Executive Officer |
August 6, 2014 |
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Report of Devon Energy Corporation (Devon) on Form 10-Q for the period ended June 30, 2014 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Thomas L. Mitchell, Executive Vice President and Chief Financial Officer of Devon, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Devon. |
/s/ Thomas L. Mitchell |
Thomas L. Mitchell |
Executive Vice President and Chief Financial Officer |
August 6, 2014 |