UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): May 7, 2014
DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
| DELAWARE | 001-32318 | 73-1567067 | ||
| (State or Other Jurisdiction of Incorporation or Organization) |
(Commission File Number) |
(IRS Employer Identification Number) |
| 333 West Sheridan Avenue, Oklahoma City, Oklahoma | 73102-5015 | |
| (Address of Principal Executive Offices) | (Zip Code) |
Registrant’s telephone number, including area code: (405) 235-3611
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
Item 7.01. Regulation FD Disclosure
In accordance with General Instruction B.2. of Form 8-K, the information presented herein under Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), nor shall it be deemed incorporated by reference in any filing under the Exchange Act or Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.
Our original 2014 forward-looking estimates are included in our Form 8-K dated February 19, 2014. These estimates were 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.
In February 2014, we announced plans to divest certain non-core properties located throughout Canada and the U.S. On April 1, 2014, we completed the sale of our Canadian conventional assets to Canadian Natural Resources Limited. Accordingly, we are updating certain of our 2014 forward-looking estimates in this document to exclude the impact of the sold Canadian conventional assets from the remainder of the year as well as other operational updates. The updated estimates along with estimates that have not changed, are presented in the following pages.
In this report, financial amounts related to our Canadian operations have been converted to U.S. dollars using estimated average exchange rates of $1.00 U.S. dollar to $1.11 Canadian dollar.
Production and Prices
Set forth below are our daily production and price realization estimates for the second quarter and full year 2014. The term “core” refers to our core and emerging assets in the Anadarko Basin, Barnett Shale, Eagle Ford Shale, Mississippian-Woodford Trend, Permian Basin and Rockies Oil in the United States, as well as our Heavy Oil assets in Canada. The term “non-core” refers to our remaining properties, many of which we are in the process of divesting. The price realizations for oil and bitumen are determined using the monthly average of NYMEX settled prices on each trading day for the benchmark West Texas Intermediate crude oil price at Cushing, Oklahoma. The price realizations for natural gas are determined using the first-of-month South Louisiana Henry Hub price index as published in Inside FERC.
| Quarter 2 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Daily Production |
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| Oil and bitumen (MBbls/d) |
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| United States Core |
125 | 130 | 124 | 136 | ||||||||||||
| Canada Core |
75 | 80 | 74 | 80 | ||||||||||||
| Non-core |
4 | 4 | 5 | 7 | ||||||||||||
| Natural gas (MMcf/d) |
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| United States Core |
1,655 | 1,700 | 1,570 | 1,640 | ||||||||||||
| Canada Core |
15 | 20 | 15 | 25 | ||||||||||||
| Non-core |
220 | 230 | 300 | 320 | ||||||||||||
| Natural gas liquids (MBbls/d) |
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| United States Core |
130 | 135 | 116 | 129 | ||||||||||||
| Canada Core |
— | — | — | — | ||||||||||||
| Non-core |
5 | 10 | 8 | 10 | ||||||||||||
| Total Boe (MBbls/d) |
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| United States Core |
531 | 548 | 502 | 538 | ||||||||||||
| Canada Core |
78 | 83 | 77 | 84 | ||||||||||||
| Non-core |
46 | 52 | 63 | 70 | ||||||||||||
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| Quarter 2 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| Price Realizations |
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| Oil and bitumen - % of WTI |
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| United States |
90 | % | 100 | % | 90 | % | 100 | % | ||||||||
| Canada |
57 | % | 67 | % | 61 | % | 71 | % | ||||||||
| Natural gas - % of Henry Hub |
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| United States |
85 | % | 95 | % | 85 | % | 95 | % | ||||||||
| Canada |
83 | % | 93 | % | 83 | % | 93 | % | ||||||||
| NGLs – Realized price |
$ | 20 | $ | 25 | $ | 20 | $ | 30 | ||||||||
Commodity Price Risk Management
As of May 2, 2014, we had the following oil derivative positions associated with 2014 production. Our oil price swaps and collars settle against the average of the prompt month NYMEX West Texas Intermediate futures price.
| 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) |
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| Q2-Q4 2014 |
75,000 | $ | 94.14 | 68,555 | $ | 89.36 | $ | 100.40 | 42,000 | $ | 116.43 | |||||||||||||||||
| Q1-Q4 2015 |
76,500 | $ | 90.14 | 3,000 | $ | 85.57 | $ | 95.57 | 28,000 | $ | 116.43 | |||||||||||||||||
| Q1-Q4 2016 |
— | $ | — | — | $ | — | $ | — | 18,500 | $ | 103.11 | |||||||||||||||||
| Basis Swaps | ||||||||||
| Period |
Index | Volume (Bbls/d) | Weighted Average Differential to WTI ($/Bbl) |
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| Q2-Q4 2014 |
Western Canadian Select | 11,796 | $ | (18.16 | ) | |||||
As of May 2, 2014, we had the following open natural gas derivative positions associated with 2014 production. The first table presents our natural gas contracts that settle against the Inside FERC first-of-the-month Henry Hub index. The second table presents our natural gas contracts 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) |
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| Q2-Q4 2014 |
800,000 | $ | 4.42 | 460,000 | $ | 4.03 | $ | 4.51 | 500,000 | $ | 5.00 | |||||||||||||||||
| Q1-Q4 2015 |
210,000 | $ | 4.38 | 255,000 | $ | 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) |
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| Q2-Q4 2014 |
AECO | 94,781 | $ | (0.52 | ) | |||||
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Other Operating and Nonoperating Items
The following table includes second quarter and full year 2014 estimates of other operating and nonoperating items.
| Quarter 2 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| ($ in millions, except per Boe) | ||||||||||||||||
| Marketing & midstream operating profit (1) |
$ | 185 | $ | 215 | $ | 685 | $ | 755 | ||||||||
| Lease operating expenses per Boe |
$ | 9.00 | $ | 9.25 | $ | 8.90 | $ | 9.50 | ||||||||
| General & administrative expenses per Boe (1) |
$ | 3.20 | $ | 3.40 | $ | 2.80 | $ | 3.30 | ||||||||
| Production and property taxes as % of upstream sales (1) |
5.9 | % | 6.9 | % | 5.9 | % | 6.9 | % | ||||||||
| Depreciation, depletion and amortization per Boe (1) |
$ | 13.00 | $ | 14.00 | $ | 12.50 | $ | 14.50 | ||||||||
| Other operating items |
$ | 15 | $ | 20 | $ | 50 | $ | 80 | ||||||||
| Net financing costs (1) |
$ | 115 | $ | 125 | $ | 445 | $ | 475 | ||||||||
| Current income tax rate (1) |
2 | % | 8 | % | 2 | % | 8 | % | ||||||||
| Deferred income tax rate (1) |
28 | % | 32 | % | 28 | % | 32 | % | ||||||||
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| Total income tax rate (1) |
30 | % | 40 | % | 30 | % | 40 | % | ||||||||
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| Net earnings attributable to noncontrolling interests |
$ | 25 | $ | 35 | $ | 75 | $ | 125 | ||||||||
| (1) | Includes amounts attributable to EnLink. |
Capital Expenditures
Set forth below are our capital expenditure estimates for the second quarter and full year 2014.
| Quarter 2 | Full Year | |||||||||||||||
| Low | High | Low | High | |||||||||||||
| (In millions) | ||||||||||||||||
| Development |
$ | 1,285 | $ | 1,435 | $ | 4,770 | $ | 5,070 | ||||||||
| Exploration |
75 | 125 | 260 | 360 | ||||||||||||
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| Subtotal (1) (2) |
1,360 | 1,560 | 5,030 | 5,430 | ||||||||||||
| Capitalized G&A and interest |
90 | 100 | 385 | 415 | ||||||||||||
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| Total oil and gas |
1,450 | 1,660 | 5,415 | 5,845 | ||||||||||||
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| Midstream (2) (3) |
350 | 380 | 845 | 915 | ||||||||||||
| Corporate and other |
35 | 55 | 125 | 175 | ||||||||||||
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| Total other |
385 | 435 | 970 | 1,090 | ||||||||||||
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| Total capital expenditures |
$ | 1,835 | $ | 2,095 | $ | 6,385 | $ | 6,935 | ||||||||
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| (1) | Includes approximately $60 million in Q2 2014 and $260 million in full year 2014 attributable to non-core assets identified for divestiture. |
| (2) | Full year estimates exclude approximately $6 billion for the acquisition of Eagle Ford Shale assets. |
| (3) | Includes approximately $250 million to $300 million in Q2 2014 and $500 million to $600 million in full year 2014 attributable to EnLink. |
Information Regarding Forward-Looking Estimates
This report includes our 2014 forward-looking estimates and associated forward-looking statements regarding our expectations and plans, as well as 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. Our forward-looking estimates are also based on the completion of planned divestitures of certain non-core assets on or around year-end 2014. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control.
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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 NGLs and related products and services; exploration or drilling programs; political or regulatory events; general economic and financial market conditions; the timing of the transactions in the previous paragraph; and other risk factors we discuss in our Annual Report on Form 10-K. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by these cautionary statements. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.
| DEVON ENERGY CORPORATION | ||
| By: | /s/ Thomas L. Mitchell | |
| Thomas L. Mitchell | ||
| Executive Vice President and Chief Financial Officer | ||
Date: May 7, 2014
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