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): February 19, 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. Except as noted, our financial forecasts included in this report assume the successful closing of our planned $6 billion acquisition of Eagle Ford Shale assets from GeoSouthern Energy Corporation, which is expected to close in the first quarter of 2014. Our financial forecasts also assume the completion of planned divestitures of certain non-core assets on or around year-end 2014. As we complete divestiture transactions, we will update our financial forecasts. In addition, our financial forecasts in this report include 100% of the amounts attributable to the operation of our planned new midstream business with Crosstex Energy, Inc. (“EnLink”) subsequent to the consummation of the transaction, which is expected to close in in the first quarter of 2014. However, subsequent to the consummation of the EnLink transaction, our net earnings will be reduced by the portion of net earnings attributable to noncontrolling interests in EnLink.
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 $1.00 Canadian dollar.
Production and Prices
Set forth below are our daily production and price realization estimates for the first 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 1	 	  	Full Year	 	
 	  	Low	 	  	High	 	  	Low	 	  	High	 	
Daily Production	  				  				  				  				
Oil and bitumen (MBbls/d)	  				  				  				  				
United States Core	  	 	94	  	  	 	98	  	  	 	124	  	  	 	136	  	
Canada Core	  	 	78	  	  	 	82	  	  	 	74	  	  	 	80	  	
Non-core	  	 	13	  	  	 	15	  	  	 	12	  	  	 	14	  	
Natural gas (MMcf/d)	  				  				  				  				
United States Core	  	 	1,595	  	  	 	1,630	  	  	 	1,570	  	  	 	1,640	  	
Canada Core	  	 	15	  	  	 	25	  	  	 	15	  	  	 	25	  	
Non-core	  	 	600	  	  	 	615	  	  	 	565	  	  	 	585	  	
Natural gas liquids (MBbls/d)	  				  				  				  				
United States Core	  	 	115	  	  	 	123	  	  	 	116	  	  	 	129	  	
Canada Core	  	 	—  	  	  	 	—  	  	  	 	—  	  	  	 	—  	  	
Non-core	  	 	15	  	  	 	17	  	  	 	14	  	  	 	16	  	
Total Boe (MBbls/d)	  				  				  				  				
United States Core	  	 	475	  	  	 	493	  	  	 	502	  	  	 	538	  	
Canada Core	  	 	81	  	  	 	86	  	  	 	77	  	  	 	84	  	
Non-core	  	 	128	  	  	 	135	  	  	 	120	  	  	 	128	  	
 
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 	  	Quarter 1	 	 	Full Year	 	
 	  	Low	 	 	High	 	 	Low	 	 	High	 	
Price Realizations	  				 				 				 				
Oil and bitumen—% of WTI	  				 				 				 				
United States	  	 	90	% 	 	 	100	% 	 	 	90	% 	 	 	100	% 	
Canada	  	 	54	% 	 	 	64	% 	 	 	61	% 	 	 	71	% 	
Natural gas—% of Henry Hub	  				 				 				 				
United States	  	 	82	% 	 	 	92	% 	 	 	85	% 	 	 	95	% 	
Canada	  	 	81	% 	 	 	91	% 	 	 	83	% 	 	 	93	% 	
NGLs – Realized price	  	 	$22	  	 	 	$30	  	 	 	$20	  	 	 	$30	  	
Commodity Price Risk Management
As of February 14, 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)	 	
Q1-Q4 2014	  	 	75,000	  	  	$	94.14	  	  	 	70,453	  	  	$	89.38	  	  	$	100.58	  	  	 	42,000	  	  	$	116.43	  	
Q1-Q4 2015	  	 	46,000	  	  	$	90.19	  	  	 	—  	  	  	$	—  	  	  	$	—  	  	  	 	28,000	  	  	$	116.43	  	
Q1-Q4 2016	  	 	—  	  	  	$	—  	  	  	 	—  	  	  	$	—  	  	  	$	—  	  	  	 	18,500	  	  	$	103.11	  	
As of February 14, 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)	 	
Q1-Q4 2014	  	 	800,000	  	  	$	4.42	  	  	 	460,000	  	  	$	4.03	  	  	$	4.51	  	  	 	500,000	  	  	$	5.00	  	
Q1-Q4 2015	  	 	150,000	  	  	$	4.40	  	  	 	215,000	  	  	$	4.04	  	  	$	4.30	  	  	 	550,000	  	  	$	5.09	  	
Q1-Q4 2016	  	 	—  	  	  	$	—  	  	  	 	—  	  	  	$	—  	  	  	$	—  	  	  	 	345,000	  	  	$	5.00	  	

 	  	Basis Swaps	 	
Period	  	Index	 	  	Volume (MMBtu/d)	 	  	Weighted Average
Differential to Henry
Hub ($/MMBtu)	 	
Q1-Q4 2014	  	 	AECO	  	  	 	94,781	  	  	$	(0.52	) 	
 
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Other Operating and Nonoperating Items
The following table includes first quarter and full year 2014 estimates of other operating and nonoperating items.

 	  	Quarter 1	 	 	Full Year	 	
 	  	Low	 	 	High	 	 	Low	 	 	High	 	
 	  	($ in millions, except per Boe)	 	
Marketing & midstream operating profit (1)	  	$	125	  	 	$	155	  	 	$	685	  	 	$	755	  	
Lease operating expenses per Boe	  	$	9.30	  	 	$	9.50	  	 	$	8.90	  	 	$	9.50	  	
General & administrative expenses per Boe (1)	  	$	3.00	  	 	$	3.30	  	 	$	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)	  	$	11.40	  	 	$	12.40	  	 	$	12.50	  	 	$	14.50	  	
Other operating items	  	$	20	  	 	$	30	  	 	$	95	  	 	$	125	  	
Net financing costs (1)	  	$	103	  	 	$	113	  	 	$	458	  	 	$	488	  	
					
Current income tax rate (1)	  	 	2	% 	 	 	8	% 	 	 	2	% 	 	 	8	% 	
Deferred income tax rate (1)	  	 	28	% 	 	 	32	% 	 	 	28	% 	 	 	32	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax rate (1)	  	 	30	% 	 	 	40	% 	 	 	30	% 	 	 	40	% 	

Net earnings attributable to noncontrolling interests	  	$	0	  	 	$	5	  	 	$	10	  	 	$	50	  	

(1)	Includes amounts attributable to EnLink’s operations subsequent to consummation of the EnLink transaction.	
Capital Expenditures
Set forth below are our capital expenditure estimates for the first quarter and full year 2014.

 	  	Quarter 1	 	  	Full Year	 	
 	  	Low	 	  	High	 	  	Low	 	  	High	 	
 	  	(In millions)	 	
Development	  	$	1,205	  	  	$	1,355	  	  	$	4,770	  	  	$	5,070	  	
Exploration	  	 	55	  	  	 	105	  	  	 	260	  	  	 	360	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Subtotal (1) (2)	  	 	1,260	  	  	 	1,460	  	  	 	5,030	  	  	 	5,430	  	
Capitalized G&A and interest	  	 	90	  	  	 	105	  	  	 	385	  	  	 	415	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil and gas	  	 	1,350	  	  	 	1,565	  	  	 	5,415	  	  	 	5,845	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Midstream (3)	  	 	205	  	  	 	255	  	  	 	845	  	  	 	915	  	
Corporate and other	  	 	30	  	  	 	50	  	  	 	125	  	  	 	175	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total other	  	 	235	  	  	 	305	  	  	 	970	  	  	 	1,090	  	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total capital expenditures	  	$	1,585	  	  	$	1,870	  	  	$	6,385	  	  	$	6,935	  	

(1)	Includes approximately $110 million in Q1 2014 and $260 million in full year 2014 attributable to non-core assets identified for divestiture.	
(2)	Excludes $6 billion of capital expenditures related to the planned acquisition of Eagle Ford Shale assets.	
(3)	Includes approximately $70 million in Q1 2014 and $460 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 closing our planned $6 billion acquisition of Eagle Ford Shale assets from GeoSouthern Energy Corporation, which is expected to close in the first quarter of 2014; the consummation of our EnLink transaction, which is expected to close in the first quarter of 2014; and 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: February 19, 2014
 
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