UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2017March 31, 2018
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 or other jurisdiction of incorporation or organization) |
| (I.R.S. Employer identification No.) |
|
| |
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
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 ☑ 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 ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer |
| ☑ | Accelerated filer |
| ☐ | Non-accelerated filer |
| ☐ |
Smaller reporting company |
| ☐ | Emerging growth company |
| ☐ |
|
|
|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑
On OctoberApril 18, 2017, 525.52018, 523.4 million shares of common stock were outstanding.
FORM 10-Q
Part I. Financial Information |
| ||
Item 1. |
| 6 | |
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| 6 | |
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| 7 | |
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| 8 | |
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| 9 | |
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| 10 | |
10 | |||
11 | |||
14 | |||
15 | |||
18 | |||
19 | |||
19 | |||
20 | |||
Note 9 – Net Earnings (Loss) Per Share Attributable to Devon | 21 | ||
22 | |||
Note 11 – Supplemental Information to Statements of Cash Flows | 22 | ||
22 | |||
23 | |||
23 | |||
23 | |||
24 | |||
25 | |||
26 | |||
26 | |||
26 | |||
26 | |||
27 | |||
28 | |||
Item 2. |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations |
|
Item 3. |
| 43 | |
Item 4. |
| 43 | |
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Part II. Other Information |
| ||
Item 1. |
| 44 | |
Item 1A. |
| 44 | |
Item 2. |
| 44 | |
Item 3. |
| 44 | |
Item 4. |
| 44 | |
Item 5. |
| 44 | |
Item 6. |
| 45 | |
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| 46 |
2
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon” and the “Company” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Quarterly Report on Form 10-Q:
“2015 Plan”ASC” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.
“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.Accounting Standards Codification.
“ASU” means Accounting Standards Update.
“Bbl” or “Bbls” means barrel or barrels.
“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.
“Btu” means British thermal units, a measure of heating value.
“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar amounts associated with Canada are in U.S. dollars, unless stated otherwise.
“Canadian Plan” means Devon Canada Corporation Incentive Savings Plan.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.
“E&P” means exploration and production activities.
“EnLink” means EnLink Midstream Partners, LP, a master limited partnership.
“FASB” means Financial Accounting Standards Board.
“G&A” means general and administrative expenses.
“GAAP” means U.S. generally accepted accounting principles.
“General Partner” means EnLink Midstream, LLC, the indirect general partner of EnLink.
“Inside FERC” refers to the publication Inside FERC’s Gas Market Report.
“LIBOR” means London Interbank Offered Rate.
“LOE” means lease operating expenses.
“MBbls” means thousand barrels.
“MBoe” means thousand Boe.
“Mcf” means thousand cubic feet.
“MMBoe” means million Boe.
“MMBtu” means million Btu.
3
“MMcf” means million cubic feet.
“M&M operations” means marketing and midstream revenues minus marketing and midstream expenses.
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPIS” means Oil Price Information Service.
“SEC” means United States Securities and Exchange Commission.
“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit.
“Tax Reform Legislation” means Tax Cuts and Jobs Act.
“TSR” means total shareholder return.
“Upstream operations” means upstream revenues minus production expenses.
“U.S.” means United States of America.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/d” means per day.
“/Bbl”gal” means per barrel.gallon.
“/MMBtu” means per MMBtu.
4
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” as defined by the SEC. Such statements include those concerning strategic plans, our expectations and objectives for future operations, as well as other future events or conditions, and are often identified by use of the words “expects,” “believes,” “will,” “would,” “could,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare our December 31, 20162017 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, including, but not limited to:
the volatility of oil, gas and NGL prices;
uncertainties inherent in estimating oil, gas and NGL reserves;
the extent to which we are successful in acquiring and discovering additional reserves;
the uncertainties, costs and risks involved in explorationoil and development activities;
risks related to our hedging activities;
counterparty credit risks;gas operations;
regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters;
risks related to our hedging activities;
counterparty credit risks;
risks relating to our indebtedness;
our ability to successfully complete mergers, acquisitions and divestitures;
the extent to which insurance covers any losses we may experience;cyberattack risks;
our limited control over third parties who operate some of our oil and gas properties;
midstream capacity constraints and potential interruptions in production;
the extent to which insurance covers any losses we may experience;
competition for leases, materials, people and capital;
cyberattacks targeting our systemsability to successfully complete mergers, acquisitions and infrastructure;divestitures; and
any of the other risks and uncertainties discussed in this report, our 2016 Annual Report on Form 10-K and our other filings with the SEC.
• | any of the other risks and uncertainties discussed in this report, our 2017 Annual Report on Form 10-K and our other filings with the SEC. |
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or revise our forward-looking statements based on new information, future events or otherwise.
5
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED COMPREHENSIVE STATEMENTS OF EARNINGS
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended March 31, |
| |||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
| ||||||
|
| (Unaudited) |
|
| (Unaudited) |
| ||||||||||||||||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||||||
Oil, gas and NGL sales |
| $ | 1,245 |
|
| $ | 1,113 |
|
| $ | 3,760 |
|
| $ | 3,023 |
| ||||||||
Oil, gas and NGL derivatives |
|
| (144 | ) |
|
| 79 |
|
|
| 214 |
|
|
| (30 | ) | ||||||||
Upstream revenues |
| $ | 1,319 |
|
| $ | 1,541 |
| ||||||||||||||||
Marketing and midstream revenues |
|
| 2,055 |
|
|
| 1,690 |
|
|
| 5,992 |
|
|
| 4,503 |
|
|
| 2,491 |
|
|
| 2,010 |
|
Asset dispositions and other |
|
| — |
|
|
| 1,351 |
|
|
| 10 |
|
|
| 1,351 |
| ||||||||
Total revenues and other |
|
| 3,156 |
|
|
| 4,233 |
|
|
| 9,976 |
|
|
| 8,847 |
| ||||||||
Lease operating expenses |
|
| 391 |
|
|
| 355 |
|
|
| 1,176 |
|
|
| 1,215 |
| ||||||||
Marketing and midstream operating expenses |
|
| 1,813 |
|
|
| 1,480 |
|
|
| 5,319 |
|
|
| 3,884 |
| ||||||||
General and administrative expenses |
|
| 153 |
|
|
| 141 |
|
|
| 498 |
|
|
| 482 |
| ||||||||
Production and property taxes |
|
| 71 |
|
|
| 67 |
|
|
| 227 |
|
|
| 220 |
| ||||||||
Total revenues |
|
| 3,810 |
|
|
| 3,551 |
| ||||||||||||||||
Production expenses |
|
| 543 |
|
|
| 457 |
| ||||||||||||||||
Exploration expenses |
|
| 33 |
|
|
| 95 |
| ||||||||||||||||
Marketing and midstream expenses |
|
| 2,214 |
|
|
| 1,814 |
| ||||||||||||||||
Depreciation, depletion and amortization |
|
| 400 |
|
|
| 394 |
|
|
| 1,162 |
|
|
| 1,420 |
|
|
| 537 |
|
|
| 528 |
|
Asset impairments |
|
| 2 |
|
|
| 319 |
|
|
| 9 |
|
|
| 4,851 |
|
|
| — |
|
|
| 7 |
|
Restructuring and transaction costs |
|
| — |
|
|
| (5 | ) |
|
| — |
|
|
| 266 |
| ||||||||
Other operating items |
|
| — |
|
|
| 17 |
|
|
| 11 |
|
|
| 41 |
| ||||||||
Total operating expenses |
|
| 2,830 |
|
|
| 2,768 |
|
|
| 8,402 |
|
|
| 12,379 |
| ||||||||
Operating income (loss) |
|
| 326 |
|
|
| 1,465 |
|
|
| 1,574 |
|
|
| (3,532 | ) | ||||||||
Net financing costs |
|
| 127 |
|
|
| 243 |
|
|
| 370 |
|
|
| 570 |
| ||||||||
Other nonoperating items |
|
| (73 | ) |
|
| 44 |
|
|
| (124 | ) |
|
| 150 |
| ||||||||
Asset dispositions |
|
| (12 | ) |
|
| (3 | ) | ||||||||||||||||
General and administrative expenses |
|
| 226 |
|
|
| 231 |
| ||||||||||||||||
Financing costs, net |
|
| 431 |
|
|
| 128 |
| ||||||||||||||||
Other expenses |
|
| 19 |
|
|
| (31 | ) | ||||||||||||||||
Total expenses |
|
| 3,991 |
|
|
| 3,226 |
| ||||||||||||||||
Earnings (loss) before income taxes |
|
| 272 |
|
|
| 1,178 |
|
|
| 1,328 |
|
|
| (4,252 | ) |
|
| (181 | ) |
|
| 325 |
|
Income tax expense (benefit) |
|
| 25 |
|
|
| 171 |
|
|
| 51 |
|
|
| (228 | ) |
|
| (28 | ) |
|
| 8 |
|
Net earnings (loss) |
|
| 247 |
|
|
| 1,007 |
|
|
| 1,277 |
|
|
| (4,024 | ) |
|
| (153 | ) |
|
| 317 |
|
Net earnings (loss) attributable to noncontrolling interests |
|
| 19 |
|
|
| 14 |
|
|
| 59 |
|
|
| (391 | ) | ||||||||
Net earnings attributable to noncontrolling interests |
|
| 44 |
|
|
| 14 |
| ||||||||||||||||
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
| $ | 1,218 |
|
| $ | (3,633 | ) |
| $ | (197 | ) |
| $ | 303 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 0.43 |
|
| $ | 1.90 |
|
| $ | 2.32 |
|
| $ | (7.22 | ) |
| $ | (0.38 | ) |
| $ | 0.58 |
|
Diluted |
| $ | 0.43 |
|
| $ | 1.89 |
|
| $ | 2.31 |
|
| $ | (7.22 | ) |
| $ | (0.38 | ) |
| $ | 0.58 |
|
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 247 |
|
| $ | 1,007 |
|
| $ | 1,277 |
|
| $ | (4,024 | ) |
| $ | (153 | ) |
| $ | 317 |
|
Other comprehensive earnings, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation |
|
| 1 |
|
|
| 2 |
|
|
| 1 |
|
|
| 28 |
| ||||||||
Foreign currency translation and other |
|
| (48 | ) |
|
| 8 |
| ||||||||||||||||
Pension and postretirement plans |
|
| 5 |
|
|
| 11 |
|
|
| 14 |
|
|
| 20 |
|
|
| 4 |
|
|
| 5 |
|
Other |
|
| — |
|
|
| — |
|
|
| (2 | ) |
|
| — |
| ||||||||
Other comprehensive earnings, net of tax |
|
| 6 |
|
|
| 13 |
|
|
| 13 |
|
|
| 48 |
|
|
| (44 | ) |
|
| 13 |
|
Comprehensive earnings (loss) |
|
| 253 |
|
|
| 1,020 |
|
|
| 1,290 |
|
|
| (3,976 | ) |
|
| (197 | ) |
|
| 330 |
|
Comprehensive earnings (loss) attributable to noncontrolling interests |
|
| 19 |
|
|
| 14 |
|
|
| 59 |
|
|
| (391 | ) | ||||||||
Comprehensive earnings attributable to noncontrolling interests |
|
| 44 |
|
|
| 14 |
| ||||||||||||||||
Comprehensive earnings (loss) attributable to Devon |
| $ | 234 |
|
| $ | 1,006 |
|
| $ | 1,231 |
|
| $ | (3,585 | ) |
| $ | (241 | ) |
| $ | 316 |
|
See accompanying notes to consolidated financial statements
6
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
| ||||||||||||||||||
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||||
|
| (Unaudited) |
|
| 2018 |
|
| 2017 |
| |||||||||||||||
|
| (Millions) |
|
| (Unaudited) |
| ||||||||||||||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 247 |
|
| $ | 1,007 |
|
| $ | 1,277 |
|
| $ | (4,024 | ) |
| $ | (153 | ) |
| $ | 317 |
|
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Adjustments to reconcile net earnings to net cash from operating activities: |
|
|
|
|
|
|
|
| ||||||||||||||||
Depreciation, depletion and amortization |
|
| 400 |
|
|
| 394 |
|
|
| 1,162 |
|
|
| 1,420 |
|
|
| 537 |
|
|
| 528 |
|
Asset impairments |
|
| 2 |
|
|
| 319 |
|
|
| 9 |
|
|
| 4,851 |
|
|
| — |
|
|
| 7 |
|
Gains and losses on asset sales |
|
| 1 |
|
|
| (1,351 | ) |
|
| (6 | ) |
|
| (1,351 | ) | ||||||||
Deferred income tax expense (benefit) |
|
| (14 | ) |
|
| 86 |
|
|
| (20 | ) |
|
| (300 | ) | ||||||||
Commodity derivatives |
|
| 144 |
|
|
| (79 | ) |
|
| (214 | ) |
|
| 30 |
| ||||||||
Leasehold impairments |
|
| 8 |
|
|
| 42 |
| ||||||||||||||||
Accretion on discounted liabilities |
|
| 16 |
|
|
| 24 |
| ||||||||||||||||
Total (gains) losses on commodity derivatives |
|
| 41 |
|
|
| (232 | ) | ||||||||||||||||
Cash settlements on commodity derivatives |
|
| 24 |
|
|
| 12 |
|
|
| 43 |
|
|
| 15 |
|
|
| 11 |
|
|
| 8 |
|
Other derivatives and financial instruments |
|
| 9 |
|
|
| 21 |
|
|
| 16 |
|
|
| 329 |
| ||||||||
Cash settlements on other derivatives and financial instruments |
|
| — |
|
|
| 3 |
|
|
| — |
|
|
| (148 | ) | ||||||||
Asset retirement obligation accretion |
|
| 16 |
|
|
| 19 |
|
|
| 47 |
|
|
| 58 |
| ||||||||
Gain on asset dispositions |
|
| (12 | ) |
|
| (3 | ) | ||||||||||||||||
Deferred income taxes |
|
| (32 | ) |
|
| (12 | ) | ||||||||||||||||
Share-based compensation |
|
| 33 |
|
|
| 23 |
|
|
| 122 |
|
|
| 163 |
|
|
| 44 |
|
|
| 55 |
|
Early retirement of debt |
|
| 312 |
|
|
| — |
| ||||||||||||||||
Other |
|
| (85 | ) |
|
| 127 |
|
|
| (134 | ) |
|
| (31 | ) |
|
| 26 |
|
|
| (24 | ) |
Net change in working capital |
|
| 7 |
|
|
| 137 |
|
|
| 94 |
|
|
| 208 |
| ||||||||
Change in long-term other assets |
|
| 2 |
|
|
| (3 | ) |
|
| 12 |
|
|
| 10 |
| ||||||||
Change in long-term other liabilities |
|
| (10 | ) |
|
| 12 |
|
|
| 12 |
|
|
| 7 |
| ||||||||
Changes in assets and liabilities, net |
|
| 6 |
|
|
| 36 |
| ||||||||||||||||
Net cash from operating activities |
|
| 776 |
|
|
| 727 |
|
|
| 2,420 |
|
|
| 1,237 |
|
|
| 804 |
|
|
| 746 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (735 | ) |
|
| (421 | ) |
|
| (2,203 | ) |
|
| (1,659 | ) |
|
| (832 | ) |
|
| (653 | ) |
Acquisitions of property, equipment and businesses |
|
| (6 | ) |
|
| (3 | ) |
|
| (39 | ) |
|
| (1,641 | ) | ||||||||
Acquisitions of property and equipment |
|
| (6 | ) |
|
| (20 | ) | ||||||||||||||||
Divestitures of property and equipment |
|
| 48 |
|
|
| 32 |
| ||||||||||||||||
Proceeds from sale of investment |
|
| — |
|
|
| — |
|
|
| 190 |
|
|
| — |
|
|
| — |
|
|
| 190 |
|
Divestitures of property and equipment |
|
| 209 |
|
|
| 1,680 |
|
|
| 323 |
|
|
| 1,889 |
| ||||||||
Other |
|
| (1 | ) |
|
| 34 |
|
|
| (5 | ) |
|
| 7 |
|
|
| — |
|
|
| (3 | ) |
Net cash from investing activities |
|
| (533 | ) |
|
| 1,290 |
|
|
| (1,734 | ) |
|
| (1,404 | ) |
|
| (790 | ) |
|
| (454 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt, net of issuance costs |
|
| 413 |
|
|
| 816 |
|
|
| 2,208 |
|
|
| 1,662 |
|
|
| 801 |
|
|
| 813 |
|
Repayments of long-term debt |
|
| (571 | ) |
|
| (2,173 | ) |
|
| (1,950 | ) |
|
| (2,722 | ) | ||||||||
Repayments of long-term debt principal |
|
| (1,236 | ) |
|
| (587 | ) | ||||||||||||||||
Payment of installment payable |
|
| — |
|
|
| — |
|
|
| (250 | ) |
|
| — |
|
|
| (250 | ) |
|
| (250 | ) |
Net short-term debt repayments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (626 | ) | ||||||||
Early retirement of debt |
|
| — |
|
|
| (82 | ) |
|
| (6 | ) |
|
| (82 | ) |
|
| (304 | ) |
|
| — |
|
Issuance of common stock |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,469 |
| ||||||||
Issuance of subsidiary units |
|
| 414 |
|
|
| 59 |
|
|
| 486 |
|
|
| 835 |
|
|
| 1 |
|
|
| 55 |
|
Repurchases of common stock |
|
| (71 | ) |
|
| — |
| ||||||||||||||||
Dividends paid on common stock |
|
| (30 | ) |
|
| (32 | ) |
|
| (95 | ) |
|
| (190 | ) |
|
| (32 | ) |
|
| (32 | ) |
Contributions from noncontrolling interests |
|
| 18 |
|
|
| 146 |
|
|
| 47 |
|
|
| 152 |
|
|
| 23 |
|
|
| 21 |
|
Distributions to noncontrolling interests |
|
| (84 | ) |
|
| (77 | ) |
|
| (247 | ) |
|
| (224 | ) |
|
| (102 | ) |
|
| (81 | ) |
Shares exchanged for tax withholdings |
|
| (3 | ) |
|
| (2 | ) |
|
| (67 | ) |
|
| (30 | ) |
|
| (43 | ) |
|
| (61 | ) |
Other |
|
| — |
|
|
| (1 | ) |
|
| (2 | ) |
|
| (7 | ) |
|
| — |
|
|
| (2 | ) |
Net cash from financing activities |
|
| 157 |
|
|
| (1,346 | ) |
|
| 124 |
|
|
| 237 |
|
|
| (1,213 | ) |
|
| (124 | ) |
Effect of exchange rate changes on cash |
|
| 12 |
|
|
| (9 | ) |
|
| 12 |
|
|
| 5 |
|
|
| (15 | ) |
|
| (8 | ) |
Net change in cash and cash equivalents |
|
| 412 |
|
|
| 662 |
|
|
| 822 |
|
|
| 75 |
| ||||||||
Cash and cash equivalents at beginning of period |
|
| 2,369 |
|
|
| 1,723 |
|
|
| 1,959 |
|
|
| 2,310 |
| ||||||||
Cash and cash equivalents at end of period |
| $ | 2,781 |
|
| $ | 2,385 |
|
| $ | 2,781 |
|
| $ | 2,385 |
| ||||||||
Net change in cash, cash equivalents and restricted cash |
|
| (1,214 | ) |
|
| 160 |
| ||||||||||||||||
Cash, cash equivalents and restricted cash at beginning of period |
|
| 2,684 |
|
|
| 1,959 |
| ||||||||||||||||
Cash, cash equivalents and restricted cash at end of period |
| $ | 1,470 |
|
| $ | 2,119 |
| ||||||||||||||||
|
|
|
|
|
|
|
|
| ||||||||||||||||
Reconciliation of cash, cash equivalents and restricted cash: |
|
|
|
|
|
|
|
| ||||||||||||||||
Cash and cash equivalents |
| $ | 1,424 |
|
| $ | 2,119 |
| ||||||||||||||||
Restricted cash included in other current assets |
|
| 46 |
|
|
| — |
| ||||||||||||||||
Total cash, cash equivalents and restricted cash |
| $ | 1,470 |
|
| $ | 2,119 |
|
See accompanying notes to consolidated financial statements
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Unaudited) |
|
|
|
|
|
| March 31, 2018 |
|
| December 31, 2017 |
| |||
|
| (Millions, except share data) |
|
| (Unaudited) |
|
|
|
|
| ||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 2,781 |
|
| $ | 1,959 |
|
| $ | 1,424 |
|
| $ | 2,673 |
|
Accounts receivable |
|
| 1,462 |
|
|
| 1,356 |
|
|
| 1,695 |
|
|
| 1,670 |
|
Assets held for sale |
|
| — |
|
|
| 193 |
| ||||||||
Other current assets |
|
| 379 |
|
|
| 264 |
|
|
| 516 |
|
|
| 448 |
|
Total current assets |
|
| 4,622 |
|
|
| 3,772 |
|
|
| 3,635 |
|
|
| 4,791 |
|
Property and equipment, at cost: |
|
|
|
|
|
|
|
| ||||||||
Oil and gas, based on full cost accounting: |
|
|
|
|
|
|
|
| ||||||||
Subject to amortization |
|
| 78,470 |
|
|
| 75,648 |
| ||||||||
Not subject to amortization |
|
| 2,853 |
|
|
| 3,437 |
| ||||||||
Total oil and gas |
|
| 81,323 |
|
|
| 79,085 |
| ||||||||
Midstream and other |
|
| 11,097 |
|
|
| 10,455 |
| ||||||||
Total property and equipment, at cost |
|
| 92,420 |
|
|
| 89,540 |
| ||||||||
Less accumulated depreciation, depletion and amortization |
|
| (75,338 | ) |
|
| (73,350 | ) | ||||||||
Property and equipment, net |
|
| 17,082 |
|
|
| 16,190 |
| ||||||||
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 13,475 |
|
|
| 13,318 |
| ||||||||
Midstream and other property and equipment, net |
|
| 7,908 |
|
|
| 7,853 |
| ||||||||
Total property and equipment, net |
|
| 21,383 |
|
|
| 21,171 |
| ||||||||
Goodwill |
|
| 3,964 |
|
|
| 3,964 |
|
|
| 2,383 |
|
|
| 2,383 |
|
Other long-term assets |
|
| 1,891 |
|
|
| 1,987 |
|
|
| 1,915 |
|
|
| 1,896 |
|
Total assets |
| $ | 27,559 |
|
| $ | 25,913 |
|
| $ | 29,316 |
|
| $ | 30,241 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 797 |
|
| $ | 642 |
|
| $ | 862 |
|
| $ | 819 |
|
Revenues and royalties payable |
|
| 1,012 |
|
|
| 908 |
|
|
| 1,269 |
|
|
| 1,180 |
|
Short-term debt |
|
| 20 |
|
|
| — |
|
|
| 354 |
|
|
| 115 |
|
Other current liabilities |
|
| 1,003 |
|
|
| 1,066 |
|
|
| 997 |
|
|
| 1,201 |
|
Total current liabilities |
|
| 2,832 |
|
|
| 2,616 |
|
|
| 3,482 |
|
|
| 3,315 |
|
Long-term debt |
|
| 10,383 |
|
|
| 10,154 |
|
|
| 9,628 |
|
|
| 10,291 |
|
Asset retirement obligations |
|
| 1,100 |
|
|
| 1,226 |
|
|
| 1,141 |
|
|
| 1,113 |
|
Other long-term liabilities |
|
| 645 |
|
|
| 894 |
|
|
| 567 |
|
|
| 583 |
|
Deferred income taxes |
|
| 665 |
|
|
| 648 |
|
|
| 773 |
|
|
| 835 |
|
Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 525 million and 523 million shares in 2017 and 2016, respectively |
|
| 53 |
|
|
| 52 |
| ||||||||
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 526 million and 525 million shares in 2018 and 2017, respectively |
|
| 53 |
|
|
| 53 |
| ||||||||
Treasury stock, at cost, 0.4 million shares in 2018 |
|
| (12 | ) |
|
| — |
| ||||||||
Additional paid-in capital |
|
| 7,207 |
|
|
| 7,237 |
|
|
| 7,269 |
|
|
| 7,333 |
|
Accumulated deficit |
|
| (428 | ) |
|
| (1,646 | ) | ||||||||
Retained earnings |
|
| 473 |
|
|
| 702 |
| ||||||||
Accumulated other comprehensive earnings |
|
| 297 |
|
|
| 284 |
|
|
| 1,122 |
|
|
| 1,166 |
|
Total stockholders’ equity attributable to Devon |
|
| 7,129 |
|
|
| 5,927 |
|
|
| 8,905 |
|
|
| 9,254 |
|
Noncontrolling interests |
|
| 4,805 |
|
|
| 4,448 |
|
|
| 4,820 |
|
|
| 4,850 |
|
Total equity |
|
| 11,934 |
|
|
| 10,375 |
|
|
| 13,725 |
|
|
| 14,104 |
|
Total liabilities and equity |
| $ | 27,559 |
|
| $ | 25,913 |
|
| $ | 29,316 |
|
| $ | 30,241 |
|
See accompanying notes to consolidated financial statements
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| Additional |
|
| Retained |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
| ||||
|
| Common Stock |
|
| Paid-In |
|
| Earnings |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
| |||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| (Accumulated Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||
|
| (Millions) |
| |||||||||||||||||||||||||||||
Nine Months Ended September 30, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2016 |
|
| 523 |
|
| $ | 52 |
|
| $ | 7,237 |
|
| $ | (1,646 | ) |
| $ | 284 |
|
| $ | — |
|
| $ | 4,448 |
|
| $ | 10,375 |
|
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,218 |
|
|
| — |
|
|
| — |
|
|
| 59 |
|
|
| 1,277 |
|
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
Restricted stock grants, net of cancellations |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| (43 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| — |
|
|
| 43 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (95 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (95 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 96 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 96 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 12 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 545 |
|
|
| 557 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (247 | ) |
|
| (247 | ) |
Balance as of September 30, 2017 |
|
| 525 |
|
| $ | 53 |
|
| $ | 7,207 |
|
| $ | (428 | ) |
| $ | 297 |
|
| $ | — |
|
| $ | 4,805 |
|
| $ | 11,934 |
|
Nine Months Ended September 30, 2016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2015 |
|
| 418 |
|
| $ | 42 |
|
| $ | 4,996 |
|
| $ | 1,781 |
|
| $ | 230 |
|
| $ | — |
|
| $ | 3,940 |
|
| $ | 10,989 |
|
Net loss |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (3,633 | ) |
|
| — |
|
|
| — |
|
|
| (391 | ) |
|
| (4,024 | ) |
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 48 |
|
|
| — |
|
|
| — |
|
|
| 48 |
|
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| (23 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (65 | ) |
|
| (125 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (190 | ) |
Common stock issued |
|
| 103 |
|
|
| 10 |
|
|
| 2,117 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,127 |
|
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 142 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 142 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 320 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 896 |
|
|
| 1,216 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (224 | ) |
|
| (224 | ) |
Balance as of September 30, 2016 |
|
| 524 |
|
| $ | 52 |
|
| $ | 7,487 |
|
| $ | (1,977 | ) |
| $ | 278 |
|
| $ | — |
|
| $ | 4,221 |
|
| $ | 10,061 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Retained |
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| Additional |
|
| Earnings |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
|
| Common Stock |
|
| Paid-In |
|
| (Accumulated |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
| |||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||
|
| (Unaudited) |
| |||||||||||||||||||||||||||||
Three Months Ended March 31, 2018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2017 |
|
| 525 |
|
| $ | 53 |
|
| $ | 7,333 |
|
| $ | 702 |
|
| $ | 1,166 |
|
| $ | — |
|
| $ | 4,850 |
|
| $ | 14,104 |
|
Net earnings (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (197 | ) |
|
| — |
|
|
| — |
|
|
| 44 |
|
|
| (153 | ) |
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (44 | ) |
|
| — |
|
|
| — |
|
|
| (44 | ) |
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (111 | ) |
|
| — |
|
|
| (111 | ) |
Common stock retired |
|
| (3 | ) |
|
| — |
|
|
| (99 | ) |
|
| — |
|
|
| — |
|
|
| 99 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (32 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (32 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 36 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 36 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 28 |
|
|
| 27 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (102 | ) |
|
| (102 | ) |
Balance as of March 31, 2018 |
|
| 526 |
|
| $ | 53 |
|
| $ | 7,269 |
|
| $ | 473 |
|
| $ | 1,122 |
|
| $ | (12 | ) |
| $ | 4,820 |
|
| $ | 13,725 |
|
Three Months Ended March 31, 2017 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2016 |
|
| 523 |
|
| $ | 52 |
|
| $ | 7,237 |
|
| $ | (69 | ) |
| $ | 1,054 |
|
| $ | — |
|
| $ | 4,448 |
|
| $ | 12,722 |
|
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 303 |
|
|
| — |
|
|
| — |
|
|
| 14 |
|
|
| 317 |
|
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
Restricted stock grants, net of cancellations |
|
| 2 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (38 | ) |
|
| — |
|
|
| (38 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (38 | ) |
|
| — |
|
|
| — |
|
|
| 38 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (32 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (32 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 30 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 30 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 10 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 75 |
|
|
| 85 |
|
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (81 | ) |
|
| (81 | ) |
Balance as of March 31, 2017 |
|
| 526 |
|
| $ | 53 |
|
| $ | 7,239 |
|
| $ | 202 |
|
| $ | 1,067 |
|
| $ | — |
|
| $ | 4,456 |
|
| $ | 13,017 |
|
See accompanying notes to consolidated financial statementsstatement
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1.Summary of Significant Accounting Policies
The accompanying unaudited interim financial statements and notes of Devon have been prepared pursuant to the rules and regulations of the SEC. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with U.S. GAAP have been omitted. The accompanying unaudited interim financial statements and notes should be read in conjunction with the financial statements and notes included in Devon’s 20162017 Annual Report on Form 10-K.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 Devon’s results of operations and cash flows for the three-month and nine-month periods ended September 30,March 31, 2018 and 2017 and 2016 and Devon’s financial position as of September 30, 2017.March 31, 2018.
Recently Adopted Accounting Standards
In January 2017,2018, Devon adopted ASU 2016-09, 2014-09, Revenue from Contracts with Customers (ASC 606), using the modified retrospective method. See Note 2 for further discussion regarding Devon’s adoption of the revenue recognition standard.
In January 2018, Devon adopted ASU 2017-07, Compensation – Stock CompensationRetirement Benefits (Topic 718)715), ImprovementsImproving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU requires entities to Employee Share-Based Payment Accounting. Its objectivepresent the service cost component of net periodic benefit cost in the same line item as other employee compensation costs. Only the service cost component of net periodic benefit cost is eligible for capitalization. As a result of adoption of this ASU, consolidated statement of earnings presentation changes were applied retrospectively, while service cost component capitalization was applied prospectively.
In January 2018, Devon adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to simplify several aspectsshow the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the accounting for share-based payments, including income taxestotals in the statement of cash flows to the related captions in the balance sheet when awards vest orthe cash, cash equivalents, restricted cash, and restricted cash equivalents are settled, statutory withholding and forfeitures.presented in more than one line item on the balance sheet. As thea result of adoption, Devon made certain income tax presentation changes most notably prospectively presenting excess tax benefits and deficiencies into the consolidated comprehensive statementsstatement of earnings and as operating cash flows into include the consolidated statementsrequired presentation and reconciliation of cash, flows. Devon also retrospectively applied the new cash flow statement guidance dictating theequivalents, restricted cash and restricted cash equivalents retrospectively. Other than presentation, adoption of shares exchanged for tax-withholding purposes as a financing activity. The adoption of the new guidancethis ASU did not materially impact the consolidated financial statements for the nine months ended September 30, 2017 or previously reported financial information but could have a more material future impact.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill And Other (Topic 350), Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amount as part of step two of the goodwill impairment test. Under ASU 2017-04, an entity should perform its goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An impairment charge should be recognized for the amount by which the carrying amount exceeds the reporting unit's fair value. However, the impairment loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. ASU 2017-04 is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment tests within those annual periods, with early application for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. In January 2017, Devon elected to early adopt ASU 2017-04, and the adoption had no impact on theDevon’s consolidated financial statements. Devon will perform future goodwill impairment tests according to ASU 2017-04.statement of cash flows.
Issued Accounting Standards Not Yet Adopted
The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU 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 effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018, with early adoption permitted in 2017. Devon has not early adopted this ASU. The ASU is required to be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon intends to use the cumulative effect transition method and does not anticipate this ASU will have a material impact on its balance sheet or related consolidated statements of earnings, equity or cash flows. However, Devon continues to evaluate the “gross versus net” presentation of certain revenues and associated expenses in its consolidated statements of earnings. Any presentation changes would have no impact on operating income, earnings or cash flows. Devon does not expect significant changes to its annual disclosures; however, Devon’s quarterly disclosures will expand upon adoption of this ASU. Devon has implemented a process to gather and provide the quarterly disclosures required by the ASU.
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, except for some changes made to align with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019 and will2019. Early adoption is permitted, but Devon does not plan to early adopt. Currently the guidance would be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. EarlyHowever, the FASB recently issued Proposed ASU No. 2018-200, Leases (Topic 842), Targeted Improvements which would allow entities to apply the transition provisions of the new standard at its adoption is permitted, but Devon does not plan to early adopt. Devon isdate instead of at the earliest comparative period presented in the process of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact thisconsolidated financial statements. The proposed ASU will have onallow entities to continue to apply the legacy guidance in Topic 840, including its consolidated financial statements and related disclosures.disclosure requirements, in the comparative periods presented in the year the new leases standard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but would recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption rather than in the earliest period presented. Recently, the FASB issued Proposed Accounting Standards Update (ASU)ASU No. 2017-290, 2018-01, Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842. This proposed ASU would permit an entity not to apply Topic 842 to land easements and rights-of-way that exist or expired before the effective date of Topic 842 and that were not previously assessed under Topic 840.An entity would continue to apply its current accounting policy for accounting for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements and rights-of-way to determine whether the arrangement should be accounted for as a lease. For Devon, these easement and right-of-way
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.
BasedDevon has preliminarily determined its portfolio of leased assets and is reviewing all related contracts to determine the impact the adoption will have on continuing research, Devon estimates a large number of contractsits consolidated financial statements and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective.related disclosures. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls. Devon is in the process of designing processes and controls and is evaluatingimplementing a technology requirements and solutionssolution needed to comply with the requirements of this ASU. While Devon cannot currently estimate the quantitative effect that ASU 2016-02 will have on its consolidated financial statements, the adoption will increase asset and liability balances on the consolidated balance sheets due to the required recognition of right-of-use assets and corresponding lease liabilities.
The FASB issued ASU No. 2017-07,2017-12, Compensation – Retirement BenefitsDerivatives and Hedging (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.815): Targeted Improvements to Accounting for Hedging Activities. This ASU will requireexpand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with a company's risk management activities. The guidance also eliminates the requirement to separately measure and report hedge ineffectiveness. This ASU only applies to entities to present the service cost component of net periodic benefit cost in the same line item as other employee compensation costs and present the other components of net periodic benefit cost outside of operating income in the statement of earnings. Only the service cost component of net periodic benefit cost is eligiblethat elect hedge accounting, which Devon has not for capitalization. Thisderivative financial instruments. This ASU is effective for Devonannual and interim periods beginning January 1, 2018, and presentation changes2019, with early adoption permitted in 2018. The ASU is required to be adopted using a cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the statementperiod of earnings will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption to account for prior period effects rather than restating previously reported results. Devon is currently evaluating the provisions of this ASU and assessing the impact it may have on its consolidated financial statements if hedge accounting were elected by Devon will reclassify $7 million, $14 millionin the future.
The FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income - Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Topic 220). This ASU allows for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Reform Legislation. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and $16 millionallows for early adoption in any interim period after issuance of non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other nonoperating items. Such amounts arethe update. Devon is currently classified in Devon’s G&A. No other changes upon adoptingassessing the impact this ASU are expected to be material.will have on its consolidated financial statements.
Impact of ASC 606 Adoption
Devon Acquisitionsadopted ASC 606 - Revenue from Contracts with Customers (ASC 606) using the modified retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services.
In January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets
The impact of adoption in the STACK play for approximately $1.5 billion. Devon funded the acquisition with $849 million of cash, after adjustments, and $659 million of common equity shares. The purchase price allocation was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.current period results is as follows:
|
| Three Months Ended March 31, 2018 |
| |||||||||
|
| Under ASC 606 |
|
| Under ASC 605 |
|
| Increase/(Decrease) |
| |||
Upstream revenues |
| $ | 1,319 |
|
| $ | 1,257 |
|
| $ | 62 |
|
Marketing and midstream revenues |
|
| 2,491 |
|
|
| 2,629 |
|
|
| (138 | ) |
Total impacted revenues |
| $ | 3,810 |
|
| $ | 3,886 |
|
| $ | (76 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production expenses |
| $ | 543 |
|
| $ | 481 |
|
| $ | 62 |
|
Marketing and midstream expenses |
|
| 2,214 |
|
|
| 2,352 |
|
|
| (138 | ) |
Total impacted expenses |
| $ | 2,757 |
|
| $ | 2,833 |
|
| $ | (76 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
| $ | (181 | ) |
| $ | (181 | ) |
| $ | — |
|
2017Changes to upstream revenues and production expenses are due to the conclusion that Devon Asset Divestitures
In May 2017, Devon announcedrepresents the principal and controls a programpromised product before transferring it to divest approximately $1 billion of upstream assets. The non-core assets identified for monetization include select portions of the Barnett Shale focused primarilyultimate third party customer in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. Estimated proved reserves associatedaccordance with these assets were less than 1% of total U.S. proved reserves.
2016 Devon Asset Divestitures
In the second quarter of 2016, Devon divested non-core assets for approximately $200 million. Estimated proved reserves associated with these assets were less than 1% of total U.S. proved reserves.
In the third quarter of 2016,control model in several separate transactions with different purchasers, Devon divested non-core upstream assets located in east Texas, the Anadarko Basin and the Midland Basin for approximately $1.7 billion. Estimated proved reserves associated with these assets were approximately 146 MMBoe, or approximately 9% of total U.S. proved reserves.ASC
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Proceeds606. This is a change from previous conclusions reached for these agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the transactions were used primarilythird-party end customer. As a result, Devon has changed the presentation of revenues and expenses for debt repaymentthese agreements. Revenues related to these agreements are now presented on a gross basis for amounts expected to be received from third-party customers through the marketing process. Gathering, processing and transportation expenses related to support capital investment in Devon’s core resource plays.
The divestiture transactions that closed inthese agreements, incurred prior to the third quartertransfer of 2016 significantly alteredcontrol to the costs and reserves relationship of Devon’s U.S. cost center. Therefore, Devon recognized a $1.4 billion gain incustomer at the third quarter of 2016 associated with these divestitures. A summarytailgate of the gain computation follows.
|
| Three Months Ended September 30, 2016 |
| |
|
| (Millions) |
| |
Proceeds received, net of purchase price adjustments and selling costs |
| $ | 1,653 |
|
Asset retirement obligation assumed by purchasers |
|
| 250 |
|
Total consideration received |
|
| 1,903 |
|
|
|
|
|
|
Allocated oil and gas property basis sold |
|
| 355 |
|
Allocated goodwill |
|
| 197 |
|
Total assets sold |
|
| 552 |
|
|
|
|
|
|
Gain on asset sales |
| $ | 1,351 |
|
natural gas processing facilities, are now presented as production expenses.
EnLink AcquisitionsChanges to marketing and midstream revenues and expenses are due to the determination of when control is transferred. As a result, Devon has changed the classification of certain transactions from marketing and midstream revenues to expenses or from marketing and midstream expenses to revenues.
In January 2016, EnLink acquired Anadarko Basin gatheringUpstream Revenues
Upstream revenues include the sale of oil, gas and processing midstream assets, along with dedicated acreage service rightsNGL production. Oil, gas and service contracts, for approximately $1.4 billion. The purchaseNGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, allocation was $1.0 billion to intangible assetsdelivery has occurred, control has transferred and approximately $400 million to property and equipment. EnLink funded the acquisition with approximately $215 million of General Partner common units and approximately $800 million of cash, primarily funded with the issuance of EnLink preferred units. The remaining $500 millioncollectability of the purchaserevenue is probable. Devon’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price wasused to be paid within one year with the option to defer $250 millionrecognize revenue is a function of the finalcontract billing terms. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment 24 monthstypically received within 30 days of the end of the production month. Taxes assessed by governmental authorities on oil, gas and NGL sales are presented separately from the close date. The first installment payment of $250 million was paid in January 2017. The remaining $250 million payment is reported in other current liabilitiessuch revenues in the accompanying consolidated balance sheets. The accretioncomprehensive statements of earnings.
Natural gas and NGL Sales
Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at the wellhead or the inlet of the discountmidstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios, Devon evaluates whether it is reported within net financing coststhe principal or the agent in the accompanyingtransaction. Devon has concluded it is the principal under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with gathering, processing and transportation fees presented as a component of production expenses in the consolidated comprehensive statement of earnings.
In August 2016, EnLink formedcertain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the product is delivered to the ultimate third-party purchaser at a joint venturecontractually agreed-upon delivery point and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control transfers to operatethe purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and expand its midstream assetscompression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as a component of production expenses in the Delaware Basin. The joint ventureconsolidated comprehensive statement of earnings.
Oil sales
Devon’s oil sales contracts are generally structured in one of two ways. First, production is initially owned 50.1% by EnLink and 49.9% bysold at the joint venture partner. EnLink contributed approximately $244 millionwellhead at an agreed-upon index price, net of existing non-monetary assetspricing differentials. In this scenario, revenue is recognized when control transfers to the joint venturepurchaser at the wellhead at the net price received. Alternatively, production is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and committed an additional $262 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregaterisk of approximately $400 million of capital, including initial cash contributions of approximately $138 million, and granted EnLink call rights beginning in 2021 to acquire increasing portionsloss of the joint venture partner’s interest.product. Under this arrangement, a third party is paid to transport the product and receive a specified index price from the purchaser with no deduction. In this scenario, revenue is recognized when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as gathering, processing and transportation expense as a component of production expenses in the consolidated comprehensive statement of earnings.
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Marketing and Midstream Revenues
Marketing and midstream revenues are generated as a result of performing gathering, transmission, processing, fractionation, storage, condensate stabilization, brine services and marketing, through various contractual arrangements, which include fee-based arrangements or arrangements where Devon purchases and resells commodities in connection with providing the related service and earns a net margin for its fee. Marketing and midstream revenues are recognized when performance obligations are satisfied. This occurs at the time contract specified products are sold or services are provided to third parties at a contractually fixed or determinable price, delivery occurs at a specified point or performance has occurred, control has transferred and collectability of the revenue is probable. Control is transferred from the producer when the midstream processor has discretion on the sale or further processing of the liquids. The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a third party published index price plus or minus a known differential. Devon typically receives payment for invoiced amounts within 30 days. Marketing and midstream revenues and expenses attributable to oil, gas and NGL purchases, transportation and processing contracts are reported on a gross basis when Devon takes control of the products and has risks and rewards of ownership.
For contracts where control of commodities is transferred before the service is performed, Devon generally has no performance obligation for its services, and accordingly, does not consider these revenue-generating service contracts. Based on that determination, all fees or fee-equivalent deductions stated in such contracts reduce the cost to purchase commodities. Alternatively, for contracts where control of commodities is transferred after the service is performed, Devon considers these contracts to contain performance obligations for its services. Accordingly, Devon considers the satisfaction of these performance obligations as revenue-generating and recognizes these fees as midstream services revenue at the time its performance obligations are satisfied. For contracts where control of commodities is never transferred, Devon simply earns a fee for its services and recognizes these fees as midstream services revenue at the time its performance obligations are satisfied.
Satisfaction of Performance Obligations and Revenue Recognitions
Since Devon has a right to consideration from its customers in amounts that correspond directly to the value that the customer receives from the performance completed on each contract, Devon applies the practical expedient in ASC 606 that allows recognition of revenue in the amount to which there is a right to invoice and prevents the need to estimate a transaction price for each contract and allocating that transaction price to the performance obligations within each contract. Devon recognizes revenue for sales or services at the time the natural gas, NGLs, crude oil or condensate are delivered at a fixed or determinable price.
Transaction Price Allocated to Remaining Performance Obligations
Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Contract Balances
Cash received relating to future performance obligations are deferred and recognized when all revenue recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as of March 31, 2018. Devon’s product sales and marketing and midstream contracts do not give rise to contract assets under ASC 606.
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Revenue from both upstream revenues and marketing and midstream revenues represent revenue from contracts with customers and these revenue line items are reflected in the consolidated comprehensive statements of earnings. The following table presents revenue from contracts with customers that are disaggregated based on the type of good or service. During the quarter ended March 31, 2018, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue.
|
| Three Months Ended March 31, 2018 |
| |||||||||||||
|
| U.S. |
|
| Canada |
|
| EnLink (1) |
|
| Total |
| ||||
Revenues from contracts with customers: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
| $ | 677 |
|
| $ | 230 |
|
| $ | — |
|
| $ | 907 |
|
Gas |
|
| 255 |
|
|
| — |
|
|
| — |
|
|
| 255 |
|
NGL |
|
| 198 |
|
|
| — |
|
|
| — |
|
|
| 198 |
|
Oil, gas and NGL sales |
|
| 1,130 |
|
|
| 230 |
|
|
| — |
|
|
| 1,360 |
|
Oil, gas and NGL derivatives |
|
| (113 | ) |
|
| 72 |
|
|
| — |
|
|
| (41 | ) |
Total upstream revenues |
|
| 1,017 |
|
|
| 302 |
|
|
| — |
|
|
| 1,319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering and transportation |
|
| — |
|
|
| — |
|
|
| 56 |
|
|
| 56 |
|
Processing |
|
| — |
|
|
| — |
|
|
| 15 |
|
|
| 15 |
|
NGL services |
|
| — |
|
|
| — |
|
|
| 16 |
|
|
| 16 |
|
Oil services |
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| 6 |
|
Total midstream services revenue |
|
| — |
|
|
| — |
|
|
| 93 |
|
|
| 93 |
|
Oil and condensate |
|
| 531 |
|
|
| 17 |
|
|
| 632 |
|
|
| 1,180 |
|
Gas |
|
| 155 |
|
|
| — |
|
|
| 286 |
|
|
| 441 |
|
NGL |
|
| 176 |
|
|
| — |
|
|
| 601 |
|
|
| 777 |
|
Total product sales |
|
| 862 |
|
|
| 17 |
|
|
| 1,519 |
|
|
| 2,398 |
|
Total marketing and midstream revenues |
|
| 862 |
|
|
| 17 |
|
|
| 1,612 |
|
|
| 2,491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues from contracts with customers |
| $ | 1,879 |
|
| $ | 319 |
|
| $ | 1,612 |
|
| $ | 3,810 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) Amounts presented net of eliminations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon Divestitures
In March 2018, Devon entered into a definitive agreement to sell a portion of its Barnett Shale assets, primarily located in Johnson County for $553 million, before purchase price adjustments. The transaction is expected to close in the second quarter of 2018. Estimated proved reserves associated with these assets are approximately 10% of total proved reserves. Devon anticipates the impact of the Johnson County divestiture will result in an adjustment to its capitalized costs with no gain recognition in the consolidated statement of earnings. In conjunction with the divestiture, Devon will settle certain gas processing contracts and expects to recognize an approximate $40 million settlement expense.
EnLink Asset Divestitures
During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Objectives and Strategies
Devon periodically enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production to hedge future prices received. Additionally, Devon and EnLink periodically enter into derivative financial instruments with respect to a portion of their oil, gas and NGL marketing activities. These commodity derivative financial instruments include financial price swaps, basis swaps and costless price collars. Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility and foreign exchange forward contracts to manage its exposure to fluctuations in the U.S. and Canadian dollar exchange rates. As of September 30, 2017,March 31, 2018, Devon did not have any open foreign exchange contracts.
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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 Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally contain provisions that provide for collateral payments if Devon’s or its counterparty’s credit rating falls below certain credit rating levels.
Commodity Derivatives
As of September 30, 2017,March 31, 2018, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
|
| Price Swaps |
|
| Price Collars |
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||||||||||||||||
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 ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
| ||||||||||
Q4 2017 |
|
| 82,167 |
|
| $ | 53.87 |
|
|
| 79,200 |
|
| $ | 45.51 |
|
| $ | 57.41 |
| ||||||||||||||||||||
Q1-Q4 2018 |
|
| 22,792 |
|
| $ | 51.13 |
|
|
| 34,121 |
|
| $ | 45.71 |
|
| $ | 55.71 |
| ||||||||||||||||||||
Q2-Q4 2018 |
|
| 58,855 |
|
| $ | 53.74 |
|
|
| 83,167 |
|
| $ | 50.28 |
|
| $ | 60.28 |
| ||||||||||||||||||||
Q1-Q4 2019 |
|
| 1,356 |
|
| $ | 49.79 |
|
|
| 2,096 |
|
| $ | 44.10 |
|
| $ | 54.10 |
|
|
| 17,030 |
|
| $ | 55.37 |
|
|
| 43,290 |
|
| $ | 50.94 |
|
| $ | 60.94 |
|
|
| Oil Basis Swaps |
| |||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
| ||
Q4 2017 |
| Midland Sweet |
|
| 20,000 |
|
| $ | (0.41 | ) |
Q4 2017 |
| Western Canadian Select |
|
| 87,304 |
|
| $ | (14.57 | ) |
Q1-Q4 2018 |
| Midland Sweet |
|
| 23,000 |
|
| $ | (1.02 | ) |
Q1-Q4 2018 |
| Western Canadian Select |
|
| 59,718 |
|
| $ | (14.85 | ) |
Q1-Q4 2019 |
| Midland Sweet |
|
| 1,000 |
|
| $ | (0.80 | ) |
|
| Oil Basis Swaps |
|
| Oil Basis Collars |
| |||||||||||||||||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Differential to WTI ($/Bbl) |
|
| Weighted Average Ceiling Differential to WTI ($/Bbl) |
| ||||||||||
Q2-Q4 2018 |
| Midland Sweet |
|
| 23,000 |
|
| $ | (1.02 | ) |
|
| — |
|
| $ | — |
|
| $ | — |
| |||||
Q2-Q4 2018 |
| Argus LLS |
|
| 12,000 |
|
| $ | 3.95 |
|
|
| — |
|
| $ | — |
|
| $ | — |
| |||||
Q2-Q4 2018 |
| Western Canadian Select |
|
| 69,018 |
|
| $ | (14.91 | ) |
|
| 1,775 |
|
| $ | (15.50 | ) |
| $ | (13.93 | ) | |||||
Q1-Q4 2019 |
| Midland Sweet |
|
| 28,000 |
|
| $ | (0.46 | ) |
|
| — |
|
| $ | — |
|
| $ | — |
|
|
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of September 30, 2017,March 31, 2018, Devon had the following open natural gas derivative positions. The first table presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The second table presents Devon’s natural gas swaps that settle against the NYMEX last day settle natural gas index. The third table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average Ceiling Price ($/MMBtu) |
| |||||
Q4 2017 |
|
| 331,196 |
|
| $ | 3.21 |
|
|
| 455,000 |
|
| $ | 3.03 |
|
| $ | 3.41 |
|
Q1-Q4 2018 |
|
| 261,888 |
|
| $ | 3.09 |
|
|
| 149,982 |
|
| $ | 2.99 |
|
| $ | 3.30 |
|
Q1-Q4 2019 |
|
| 6,164 |
|
| $ | 3.08 |
|
|
| 8,630 |
|
| $ | 2.92 |
|
| $ | 3.22 |
|
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q4 2017 |
| Panhandle Eastern Pipe Line |
|
| 150,000 |
|
| $ | (0.34 | ) |
Q4 2017 |
| El Paso Natural Gas |
|
| 80,000 |
|
| $ | (0.13 | ) |
Q4 2017 |
| Houston Ship Channel |
|
| 35,000 |
|
| $ | 0.06 |
|
Q4 2017 |
| Transco Zone 4 |
|
| 205,000 |
|
| $ | 0.03 |
|
Q1-Q4 2018 |
| Panhandle Eastern Pipe Line |
|
| 50,000 |
|
| $ | (0.29 | ) |
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average Ceiling Price ($/MMBtu) |
| |||||
Q2-Q4 2018 |
|
| 378,033 |
|
| $ | 2.97 |
|
|
| 201,867 |
|
| $ | 2.79 |
|
| $ | 3.10 |
|
Q1-Q4 2019 |
|
| 52,622 |
|
| $ | 2.90 |
|
|
| 52,844 |
|
| $ | 2.77 |
|
| $ | 3.07 |
|
|
|
|
|
|
|
|
|
|
|
| Price Swaps |
| |||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
| ||
Q1-Q4 2019 |
|
| 128,164 |
|
| $ | 2.78 |
|
Q1-Q4 2020 |
|
| 116,364 |
|
| $ | 2.73 |
|
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q2-Q4 2018 |
| Panhandle Eastern Pipe Line |
|
| 90,000 |
|
| $ | (0.43) |
|
Q2-Q4 2018 |
| El Paso Natural Gas |
|
| 30,000 |
|
| $ | (0.85) |
|
Q2-Q4 2018 |
| Houston Ship Channel |
|
| 60,000 |
|
| $ | (0.01) |
|
Q2-Q4 2018 |
| Transco Zone 4 |
|
| 10,036 |
|
| $ | (0.03) |
|
Q1-Q4 2019 |
| Houston Ship Channel |
|
| 32,500 |
|
| $ | (0.02) |
|
Q1-Q4 2019 |
| Transco Zone 4 |
|
| 7,397 |
|
| $ | (0.03) |
|
As of September 30, 2017,March 31, 2018, Devon had the following open NGL derivative positions. Devon’s NGL positions settle against the average of the prompt month OPIS Mont Belvieu, Texas index.
|
|
|
| Price Swaps |
|
| Price Collars |
|
|
|
| Price Swaps |
| |||||||||||||||||||
Period |
| Product |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
|
| Product |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
| |||||||
Q4 2017 |
| Propane |
|
| 2,663 |
|
| $ | 31.98 |
|
|
| 1,000 |
|
| $ | 28.35 |
|
| $ | 30.45 |
| ||||||||||
Q2-Q4 2018 |
| Ethane |
|
| 6,500 |
|
| $ | 11.86 |
| ||||||||||||||||||||||
Q2-Q4 2018 |
| Natural Gasoline |
|
| 5,500 |
|
| $ | 54.24 |
| ||||||||||||||||||||||
Q2-Q4 2018 |
| Normal Butane |
|
| 6,750 |
|
| $ | 38.46 |
| ||||||||||||||||||||||
Q2-Q4 2018 |
| Propane |
|
| 10,500 |
|
| $ | 33.30 |
|
As of September 30, 2017,March 31, 2018, EnLink had the following open derivative positions associated with gas processing and fractionation. EnLink’s NGL positions settle by purity product against the average of the prompt month OPIS Mont Belvieu, Texas index. EnLink’s natural gas positions settle against the Henry Hub Gas Daily index.
Period |
| Product |
| Volume (Total) |
| Weighted Average Price Paid |
| Weighted Average Price Received | |||
|
| Propane |
|
|
|
| MBbls |
| Index |
| $ |
|
|
|
|
|
|
|
|
| Index |
| $ |
Interest Rate Derivatives
As of September 30, 2017, Devon had the following open interest rate derivative positions:
Notional |
|
| Rate Received |
|
| Rate Paid |
|
| Expiration | |||
(Millions) |
|
|
|
|
|
|
|
|
|
|
| |
$ | 750 |
|
| Three Month LIBOR |
|
|
| 2.98% |
|
| December 2048 (1) | |
$ | 100 |
|
|
| 1.76% |
|
| Three Month LIBOR |
|
| January 2019 |
|
|
1416
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of March 31, 2018, Devon had the following open interest rate derivative positions:
Notional |
|
| Rate Received |
|
| Rate Paid |
|
| Expiration | |
$ | 750 |
|
| Three Month LIBOR |
|
| 2.98% |
|
| December 2048 (1) |
$ | 100 |
|
| 1.76% |
|
| Three Month LIBOR |
|
| January 2019 |
(1) | Mandatory settlement in December 2018. |
Financial Statement Presentation
The following table presents the net gains and losses by derivative financial instrument type followed by the corresponding individual consolidated comprehensive statements of earnings caption.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL derivatives |
| $ | (144 | ) |
| $ | 79 |
|
| $ | 214 |
|
| $ | (30 | ) |
Marketing and midstream revenues |
|
| (5 | ) |
|
| (1 | ) |
|
| 3 |
|
|
| (7 | ) |
Interest rate derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other nonoperating items |
|
| (4 | ) |
|
| (20 | ) |
|
| (19 | ) |
|
| (163 | ) |
Foreign currency derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other nonoperating items |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (159 | ) |
Net gains (losses) recognized |
| $ | (153 | ) |
| $ | 58 |
|
| $ | 198 |
|
| $ | (359 | ) |
|
| Three Months Ended March 31, |
| |||||
|
| 2018 |
|
| 2017 |
| ||
Commodity derivatives: |
|
|
|
|
|
|
|
|
Upstream revenues |
| $ | (41 | ) |
| $ | 232 |
|
Marketing and midstream revenues |
|
| 1 |
|
|
| 4 |
|
Interest rate derivatives: |
|
|
|
|
|
|
|
|
Other expenses |
|
| 46 |
|
|
| 5 |
|
Net gains recognized |
| $ | 6 |
|
| $ | 241 |
|
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheet caption.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Millions) |
|
| March 31, 2018 |
|
| December 31, 2017 |
| |||||||
Commodity derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
| $ | 39 |
|
| $ | 9 |
|
| $ | 193 |
|
| $ | 209 |
|
Other long-term assets |
|
| 4 |
|
|
| 1 |
|
|
| 22 |
|
|
| 2 |
|
Interest rate derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Total derivative assets |
| $ | 44 |
|
| $ | 11 |
|
| $ | 216 |
|
| $ | 212 |
|
Commodity derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | 53 |
|
| $ | 187 |
|
| $ | 328 |
|
| $ | 267 |
|
Other long-term liabilities |
|
| 7 |
|
|
| 16 |
|
|
| 27 |
|
|
| 27 |
|
Interest rate derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
|
| 1 |
|
|
| — |
|
|
| 22 |
|
|
| 64 |
|
Other long-term liabilities |
|
| 61 |
|
|
| 41 |
| ||||||||
Total derivative liabilities |
| $ | 122 |
|
| $ | 244 |
|
| $ | 377 |
|
| $ | 358 |
|
1517
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
In the second quarter of 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards under the 2015 Plan that are transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.
The following table below presents the effects of share-based compensation expense included in Devon’s accompanying consolidated comprehensive statements of earnings. Gross G&A expense for the first nine months of 2017 and 2016 includes $28 million and $18 million, respectively, of unit-based compensation related to grants made under EnLink’s long-term incentive plans.
The vesting for certain share-based awards was accelerated in 2016 in conjunction with the reduction of workforce described in Note 6. For the nine months ended September 30, 2016, approximately $60 million of associated expense for these accelerated awards is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.
|
| Nine Months Ended September 30, |
| |||||
|
| 2017 |
|
| 2016 |
| ||
|
| (Millions) |
| |||||
Gross G&A for share-based compensation |
| $ | 141 |
|
| $ | 117 |
|
Share-based compensation expense capitalized pursuant to the full cost method of accounting for oil and gas properties |
| $ | 31 |
|
| $ | 30 |
|
Related income tax benefit |
| $ | 3 |
|
| $ | 3 |
|
|
| Three Months Ended March 31, |
| |||||
|
| 2018 |
|
| 2017 |
| ||
G&A |
| $ | 37 |
|
| $ | 34 |
|
Exploration expenses |
|
| 2 |
|
|
| 2 |
|
Total Devon |
|
| 39 |
|
|
| 36 |
|
G&A |
|
| 3 |
|
|
| 14 |
|
Marketing and midstream expenses |
|
| 2 |
|
|
| 5 |
|
Total EnLink |
|
| 5 |
|
|
| 19 |
|
Total |
| $ | 44 |
|
| $ | 55 |
|
Related income tax benefit |
| $ | 1 |
|
| $ | 1 |
|
Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first ninethree months of 2017.2018. The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-based restricted stock awards and performance share units granted under the plan.
|
| Restricted Stock |
|
| Performance-Based |
|
| Performance |
|
| Restricted Stock |
|
| Performance-Based |
|
| Performance |
| ||||||||||||||||||||||||||||||||||||
|
| Awards and Units |
|
| Restricted Stock Awards |
|
| Share Units |
|
| Awards and Units |
|
| Restricted Stock Awards |
|
| Share Units |
| ||||||||||||||||||||||||||||||||||||
|
| Awards and Units |
|
| Weighted Average Grant-Date Fair Value |
|
| Awards |
|
| Weighted Average Grant-Date Fair Value |
|
| Units |
|
|
|
| Weighted Average Grant-Date Fair Value |
|
| Awards and Units |
|
| Weighted Average Grant-Date Fair Value |
|
| Awards |
|
| Weighted Average Grant-Date Fair Value |
|
| Units |
|
|
|
| Weighted Average Grant-Date Fair Value |
| ||||||||||||||
|
| (Thousands, except fair value data) |
|
| (Thousands, except fair value data) |
| ||||||||||||||||||||||||||||||||||||||||||||||||
Unvested at 12/31/16 |
|
| 6,407 |
|
| $ | 34.40 |
|
|
| 585 |
|
| $ | 37.60 |
|
|
| 2,604 |
|
|
| $ | 46.66 |
| |||||||||||||||||||||||||||||
Unvested at 12/31/17 |
|
| 6,328 |
|
| $ | 36.81 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
|
| $ | 41.21 |
| |||||||||||||||||||||||||||||
Granted |
|
| 2,691 |
|
| $ | 44.87 |
|
|
| 223 |
|
| $ | 44.85 |
|
|
| 1,010 |
|
|
| $ | 52.58 |
|
|
| 3,425 |
|
| $ | 35.77 |
|
|
| — |
|
| $ | — |
|
|
| 845 |
|
|
| $ | 37.40 |
| ||||
Vested |
|
| (2,321 | ) |
| $ | 39.51 |
|
|
| (233 | ) |
| $ | 41.27 |
|
|
| (832 | ) |
|
| $ | 78.19 |
|
|
| (2,286 | ) |
| $ | 38.82 |
|
|
| (227 | ) |
| $ | 43.14 |
|
|
| (571 | ) |
|
| $ | 84.22 |
| ||||
Forfeited |
|
| (252 | ) |
| $ | 36.06 |
|
|
| — |
|
| $ | — |
|
|
| (24 | ) |
|
| $ | 40.70 |
|
|
| (85 | ) |
| $ | 35.13 |
|
|
| — |
|
| $ | — |
|
|
| (3 | ) |
|
| $ | 27.12 |
| ||||
Unvested at 9/30/17 |
|
| 6,525 |
|
| $ | 36.83 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
| (1 | ) |
| $ | 41.21 |
| |||||||||||||||||||||||||||
Unvested at 3/31/18 |
|
| 7,382 |
|
| $ | 35.72 |
|
|
| 348 |
|
| $ | 36.17 |
|
|
| 3,029 |
|
| (1 | ) |
| $ | 30.35 |
|
(1) | A maximum of |
The following table presents the assumptions related to the performance share units granted in 2017,2018, as indicated in the previous summary table.
|
| 2017 |
|
| 2018 |
| ||||||||||||||
Grant-date fair value |
| $ | 51.05 |
| — |
| $ | 53.12 |
|
|
| $36.23 |
|
| — |
| $ | 37.88 |
| |
Risk-free interest rate |
| 1.50% |
|
| 2.28% |
| ||||||||||||||
Volatility factor |
| 45.8% |
|
| 45.8% |
| ||||||||||||||
Contractual term (years) |
| 2.89 |
|
| 2.89 |
|
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of September 30, 2017.March 31, 2018.
|
|
|
|
|
| Performance-Based |
|
|
|
|
|
|
|
|
|
| Performance-Based |
|
|
|
|
| ||
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| ||||||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
|
| Awards and Units |
|
| Awards |
|
| Share Units |
| ||||||
Unrecognized compensation cost (millions) |
| $ | 160 |
|
| $ | 6 |
|
| $ | 35 |
| ||||||||||||
Unrecognized compensation cost |
| $ | 213 |
|
| $ | 3 |
|
| $ | 53 |
| ||||||||||||
Weighted average period for recognition (years) |
|
| 2.5 |
|
|
| 1.8 |
|
|
| 2.0 |
|
|
| 2.9 |
|
|
| 1.5 |
|
|
| 2.2 |
|
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
In March 2017, theThe General Partner and EnLink issuedissue restricted incentive units as bonus payments to officers and certain employees. The combined grant fair value was $10 million,employees in the first quarter each year for the prior year’s performance. For the first quarter of 2018 and the total cost was recognized in the first quarter of 2017, due to the combined grant date fair value for these awards vesting immediately.was $6 million and $10 million, respectively.
The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with the General Partner’s and EnLink’s unvested restricted incentive units and performance units as of September 30, 2017.March 31, 2018.
|
| General Partner |
|
| EnLink |
|
| General Partner |
|
| EnLink |
| ||||||||||||||||||||
|
| Restricted |
|
| Performance |
|
| Restricted |
|
| Performance |
|
| Restricted |
|
| Performance |
|
| Restricted |
|
| Performance |
| ||||||||
|
| Incentive Units |
|
| Units |
|
| Incentive Units |
|
| Units |
|
| Incentive Units |
|
| Units |
|
| Incentive Units |
|
| Units |
| ||||||||
Unrecognized compensation cost (millions) |
| $ | 14 |
|
| $ | 6 |
|
| $ | 15 |
|
| $ | 6 |
| ||||||||||||||||
Unrecognized compensation cost |
| $ | 19 |
|
| $ | 8 |
|
| $ | 20 |
|
| $ | 8 |
| ||||||||||||||||
Weighted average period for recognition (years) |
|
| 1.8 |
|
|
| 2.0 |
|
|
| 1.7 |
|
|
| 1.9 |
|
|
| 2.1 |
|
|
| 2.3 |
|
|
| 2.2 |
|
|
| 2.3 |
|
Unproved Impairments
In the first quarter of 2018 and 2017, Devon allowed certain non-core acreage to expire without plans for development, resulting in unproved impairments of $8 million and $41 million, respectively. Unproved impairments are included in exploration expenses in the consolidated comprehensive statements of earnings.
The following table presents the components of asset impairments.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
U.S. oil and gas assets |
| $ | — |
|
| $ | 317 |
|
| $ | — |
|
| $ | 2,810 |
|
Canada oil and gas assets |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,166 |
|
EnLink goodwill |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 873 |
|
Other assets |
|
| 2 |
|
|
| 2 |
|
|
| 9 |
|
|
| 2 |
|
Total asset impairments |
| $ | 2 |
|
| $ | 319 |
|
| $ | 9 |
|
| $ | 4,851 |
|
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% 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 in 2016 resulted from declinessummarizes Devon’s other expenses presented in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves.
EnLink Goodwill Impairments
In the first quarteraccompanying consolidated comprehensive statement of 2016, EnLink recognized goodwill impairments. See Note 12 for additional details.earnings.
|
| Three Months Ended March 31, |
| |||||
|
| 2018 |
|
| 2017 |
| ||
Foreign exchange (gain) loss, net |
| $ | 50 |
|
| $ | (15 | ) |
Asset retirement obligation accretion |
|
| 16 |
|
|
| 17 |
|
Other, net |
|
| (47 | ) |
|
| (33 | ) |
Total |
| $ | 19 |
|
| $ | (31 | ) |
1719
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Certain of Devon’s non-Canadian foreign subsidiaries have a U.S. dollar functional currency, hold Canadian-dollar cash and engage in 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. During the first quarter of 2018, Devon recognized foreign exchange losses related to these activities resulting from the strengthening of the U.S. dollar in relation to the Canadian dollar.
6.Restructuring and Transaction Costs
The following table summarizes restructuring and transaction costs presented in the accompanying consolidated comprehensive statement of earnings.
|
| September 30, 2016 |
| |||||
|
| Three Months Ended |
|
| Nine Months Ended |
| ||
|
| (Millions) |
| |||||
2016 reduction in workforce: |
|
|
|
|
|
|
|
|
Employee related costs |
| $ | (7 | ) |
| $ | 229 |
|
Lease obligations |
|
| — |
|
|
| 17 |
|
Asset impairments |
|
| — |
|
|
| 3 |
|
Transaction costs |
|
| 2 |
|
|
| 17 |
|
Restructuring and transaction costs |
| $ | (5 | ) |
| $ | 266 |
|
The following table summarizes Devon’s restructuring liabilities.
|
| Other |
|
| Other |
|
|
|
|
| ||
|
| Current |
|
| Long-term |
|
|
|
|
| ||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
|
| (Millions) |
| |||||||||
Balance as of December 31, 2016 |
| $ | 48 |
|
| $ | 62 |
|
| $ | 110 |
|
Changes due to 2016 workforce reductions |
|
| (25 | ) |
|
| (2 | ) |
|
| (27 | ) |
Changes related to prior years' restructurings |
|
| (3 | ) |
|
| (24 | ) |
|
| (27 | ) |
Balance as of September 30, 2017 |
| $ | 20 |
|
| $ | 36 |
|
| $ | 56 |
|
Balance as of December 31, 2015 |
| $ | 13 |
|
| $ | 63 |
|
| $ | 76 |
|
Changes due to 2016 workforce reductions |
|
| 58 |
|
|
| 13 |
|
|
| 71 |
|
Changes related to prior years' restructurings |
|
| 5 |
|
|
| (8 | ) |
|
| (3 | ) |
Balance as of September 30, 2016 |
| $ | 76 |
|
| $ | 68 |
|
| $ | 144 |
|
|
| Other |
|
| Other |
|
|
|
|
| ||
|
| Current |
|
| Long-term |
|
|
|
|
| ||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
Balance as of December 31, 2017 |
| $ | 19 |
|
| $ | 31 |
|
| $ | 50 |
|
Changes related to prior years' restructurings |
|
| (1 | ) |
|
| (4 | ) |
|
| (5 | ) |
Balance as of March 31, 2018 |
| $ | 18 |
|
| $ | 27 |
|
| $ | 45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2016 |
|
| 48 |
|
|
| 62 |
|
|
| 110 |
|
Changes related to prior years' restructurings |
|
| (15 | ) |
|
| (5 | ) |
|
| (20 | ) |
Balance as of March 31, 2017 |
| $ | 33 |
|
| $ | 57 |
|
| $ | 90 |
|
Reduction in Workforce
In the first nine months of 2016,April 2018, Devon recognized $229 million in employee-related costs associated with a reduction in workforce. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $30 million resulted from estimated settlements of defined retirement benefits.
announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure. As a result, Devon will incur additional restructuring charges and liabilities, ranging from $75 million to $100 million, beginning in the second quarter of the reduction of workforce, Devon ceased using certain office space that was subject to non-cancellable operating lease arrangements. Devon recognized restructuring costs that represent the present value of its future obligations under the leases and impairment charges for leasehold improvements and furniture associated with the office space it ceased using.
Transaction Costs
In the first nine months of 2016, Devon and EnLink recognized transaction costs primarily associated with the closing of the acquisitions discussed in Note 2.2018.
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents Devon’s 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 September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||||
|
| (Millions) |
|
| 2018 |
|
| 2017 |
| |||||||||||||||
Current income tax expense |
| $ | 39 |
|
| $ | 85 |
|
| $ | 71 |
|
| $ | 72 |
|
| $ | 4 |
|
| $ | 20 |
|
Deferred income tax expense (benefit) |
|
| (14 | ) |
|
| 86 |
|
|
| (20 | ) |
|
| (300 | ) | ||||||||
Deferred income tax benefit |
|
| (32 | ) |
|
| (12 | ) | ||||||||||||||||
Total income tax expense (benefit) |
| $ | 25 |
|
| $ | 171 |
|
| $ | 51 |
|
| $ | (228 | ) |
| $ | (28 | ) |
| $ | 8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 21 | % |
|
| 35 | % |
Deferred tax asset valuation allowance |
|
| (9 | %) |
|
| (35 | %) |
|
| (25 | %) |
|
| (20 | %) | ||||||||
Non-deductible goodwill impairments |
|
| 0 | % |
|
| 6 | % |
|
| 0 | % |
|
| (9 | %) | ||||||||
Change in unrecognized tax benefits |
|
| 3 | % |
|
| 7 | % |
|
| 1 | % |
|
| (2 | %) | ||||||||
Taxation on Canadian operations |
|
| (1 | %) |
|
| 0 | % |
|
| 0 | % |
|
| (3 | %) | ||||||||
State income taxes |
|
| 0 | % |
|
| 2 | % |
|
| 0 | % |
|
| 1 | % |
|
| 1 | % |
|
| 2 | % |
Other |
|
| (19 | %) |
|
| 0 | % |
|
| (7 | %) |
|
| 3 | % |
|
| (5 | %) |
|
| (1 | %) |
Deferred tax asset valuation allowance |
|
| (2 | %) |
|
| (34 | %) | ||||||||||||||||
Effective income tax rate |
|
| 9 | % |
|
| 15 | % |
|
| 4 | % |
|
| 5 | % |
|
| 15 | % |
|
| 2 | % |
Devon estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
Throughout 2016 and through Under the first nine months of 2017, Devon continued to maintain a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to full cost impairments. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.
Devon provided an additional $796 million toTax Reform Legislation, the U.S. segment valuation allowance in the first nine months of 2016 based on the financial loss recorded during the period. Also, during the third quarter of 2016, Devon’s Canadian segment recorded a $71 million partial valuation allowance. Devoncorporate income tax rate was reduced its U.S. segment valuation allowance by $348 million in the first nine months of 2017 based on the financial income recorded during the period.to 21% effective January 1, 2018.
Also inIn the table above, the “other” effect is primarily composed of permanent differences for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, such items have an insignificant impact on ourDevon’s effective income tax rate. However, these items have a more noticeable impact to ourthe rate in the thirdfirst quarter of 20172018 due to lower relative earnings during the period. During the third quarter of
Throughout 2017 “other” is primarily related to the taxation of foreign earnings and other financing items.
Inthrough the first quarter of 2016, EnLink2018, Devon continued to maintain a 100% valuation allowance against its U.S. deferred tax assets resulting from prior year cumulative financial losses largely due to oil and gas impairments and significant net
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
operating losses for U.S. federal and state income tax. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.
During the first quarter of 2018, Devon repatriated approximately $92 million from certain international entities. This repatriation had no tax impact.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows Devon to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation are expected over the next 12 months, Devon considers the accounting of the transition tax, deferred tax remeasurements and other items to be incomplete due to the forthcoming guidance and ongoing analysis of Devon’s tax positions. Devon expects to complete its analysis within the measurement period in accordance with SAB 118. No material changes to the provisional amounts recorded goodwill impairments totaling $873 million. These impairments are not deductible for purposesin the fourth quarter of calculating income tax and, therefore,2017 have an impact onbeen made during the effective tax rate.first quarter of 2018.
Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. The timing of resolution of income tax examinations is uncertain as are the amounts and timing of tax payments that are part of any audit settlement process. Devon believes that within the next 12 months it is reasonably possible that certain tax examinations will be resolved by settlement with the taxing authorities.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table reconciles net earnings (loss) attributable to Devon and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||||
|
| (Millions, except per share amounts) |
|
| 2018 |
|
| 2017 |
| |||||||||||||||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
| $ | 1,218 |
|
| $ | (3,633 | ) |
| $ | (197 | ) |
| $ | 303 |
|
Attributable to participating securities |
|
| (2 | ) |
|
| (11 | ) |
|
| (13 | ) |
|
| (1 | ) |
|
| — |
|
|
| (3 | ) |
Basic and diluted earnings (loss) |
| $ | 226 |
|
| $ | 982 |
|
| $ | 1,205 |
|
| $ | (3,634 | ) |
| $ | (197 | ) |
| $ | 300 |
|
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding - total |
|
| 526 |
|
|
| 524 |
|
|
| 525 |
|
|
| 509 |
|
|
| 527 |
|
|
| 525 |
|
Attributable to participating securities |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (7 | ) |
|
| (6 | ) |
Common shares outstanding - basic |
|
| 520 |
|
|
| 518 |
|
|
| 519 |
|
|
| 503 |
|
|
| 520 |
|
|
| 519 |
|
Dilutive effect of potential common shares issuable |
|
| 3 |
|
|
| 3 |
|
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
Common shares outstanding - diluted |
|
| 523 |
|
|
| 521 |
|
|
| 522 |
|
|
| 503 |
|
|
| 520 |
|
|
| 522 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 0.43 |
|
| $ | 1.90 |
|
| $ | 2.32 |
|
| $ | (7.22 | ) |
| $ | (0.38 | ) |
| $ | 0.58 |
|
Diluted |
| $ | 0.43 |
|
| $ | 1.89 |
|
| $ | 2.31 |
|
| $ | (7.22 | ) |
| $ | (0.38 | ) |
| $ | 0.58 |
|
Antidilutive options (1) |
|
| 2 |
|
|
| 3 |
|
|
| 2 |
|
|
| 3 |
|
|
| 2 |
|
|
| 3 |
|
(1) | Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings |
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Components of other comprehensive earnings consist of the following:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated foreign currency translation |
| $ | 456 |
|
| $ | 450 |
|
| $ | 456 |
|
| $ | 424 |
|
Change in cumulative translation adjustment |
|
| 17 |
|
|
| (1 | ) |
|
| 31 |
|
|
| 52 |
|
Income tax benefit (expense) |
|
| (16 | ) |
|
| 3 |
|
|
| (30 | ) |
|
| (24 | ) |
Ending accumulated foreign currency translation |
|
| 457 |
|
|
| 452 |
|
|
| 457 |
|
|
| 452 |
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (163 | ) |
|
| (185 | ) |
|
| (172 | ) |
|
| (194 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 5 |
|
|
| 7 |
|
|
| 14 |
|
|
| 20 |
|
Income tax benefit |
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| — |
|
Ending accumulated pension and postretirement benefits |
|
| (158 | ) |
|
| (174 | ) |
|
| (158 | ) |
|
| (174 | ) |
Other |
|
| (2 | ) |
|
| — |
|
|
| (2 | ) |
|
| — |
|
Accumulated other comprehensive earnings, net of tax |
| $ | 297 |
|
| $ | 278 |
|
| $ | 297 |
|
| $ | 278 |
|
|
| Three Months Ended March 31, |
| |||||
|
| 2018 |
|
| 2017 |
| ||
Foreign currency translation and other: |
|
|
|
|
|
|
|
|
Beginning accumulated foreign currency translation and other |
| $ | 1,309 |
|
| $ | 1,226 |
|
Change in cumulative translation adjustment and other |
|
| (61 | ) |
|
| 11 |
|
Income tax benefit (expense) |
|
| 13 |
|
|
| (3 | ) |
Ending accumulated foreign currency translation and other |
|
| 1,261 |
|
| $ | 1,234 |
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (143 | ) |
|
| (172 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 4 |
|
|
| 5 |
|
Ending accumulated pension and postretirement benefits |
|
| (139 | ) |
|
| (167 | ) |
Accumulated other comprehensive earnings, net of tax |
| $ | 1,122 |
|
| $ | 1,067 |
|
(1) | These accumulated other comprehensive earnings components are included in the computation of net periodic benefit cost, which is a component of |
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended March 31, |
| |||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2018 |
|
| 2017 |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Net change in working capital accounts, net of assets and liabilities assumed: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Changes in assets and liabilities, net |
|
|
|
|
|
|
|
| ||||||||||||||||
Accounts receivable |
| $ | (215 | ) |
| $ | 81 |
|
| $ | (85 | ) |
| $ | 87 |
|
| $ | (27 | ) |
| $ | 48 |
|
Income taxes receivable |
|
| — |
|
|
| 6 |
|
|
| 8 |
|
|
| 107 |
| ||||||||
Other current assets |
|
| 12 |
|
|
| 98 |
|
|
| (43 | ) |
|
| 242 |
|
|
| (79 | ) |
|
| (21 | ) |
Other long-term assets |
|
| (52 | ) |
|
| 1 |
| ||||||||||||||||
Accounts payable |
|
| 48 |
|
|
| (34 | ) |
|
| 98 |
|
|
| (185 | ) |
|
| 14 |
|
|
| 4 |
|
Revenues and royalties payable |
|
| 63 |
|
|
| 40 |
|
|
| 92 |
|
|
| 34 |
|
|
| 84 |
|
|
| 73 |
|
Other current liabilities |
|
| 99 |
|
|
| (54 | ) |
|
| 24 |
|
|
| (77 | ) |
|
| 76 |
|
|
| (89 | ) |
Net change in working capital |
| $ | 7 |
|
| $ | 137 |
|
| $ | 94 |
|
| $ | 208 |
| ||||||||
Other long-term liabilities |
|
| (10 | ) |
|
| 20 |
| ||||||||||||||||
Total |
| $ | 6 |
|
| $ | 36 |
| ||||||||||||||||
Interest paid (net of capitalized interest) |
| $ | 49 |
|
| $ | 113 |
|
| $ | 285 |
|
| $ | 402 |
|
| $ | 76 |
|
| $ | 92 |
|
Income taxes paid (received) |
| $ | — |
|
| $ | (7 | ) |
| $ | (1) |
|
| $ | (130 | ) | ||||||||
Income taxes paid |
| $ | 1 |
|
| $ | 3 |
|
Devon’s acquisition of certain STACK assets during the first three months of 2016 included the noncash issuance of Devon common stock. See Note 2 for additional details.
EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016 included the noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 2 for additional details.
Components of accounts receivable include the following:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Millions) |
|
| March 31, 2018 |
|
| December 31, 2017 |
| |||||||
Oil, gas and NGL sales |
| $ | 528 |
|
| $ | 487 |
|
| $ | 536 |
|
| $ | 559 |
|
Joint interest billings |
|
| 111 |
|
|
| 110 |
|
|
| 132 |
|
|
| 134 |
|
Marketing and midstream revenues |
|
| 792 |
|
|
| 708 |
|
|
| 989 |
|
|
| 959 |
|
Other |
|
| 44 |
|
|
| 69 |
|
|
| 50 |
|
|
| 29 |
|
Gross accounts receivable |
|
| 1,475 |
|
|
| 1,374 |
|
|
| 1,707 |
|
|
| 1,681 |
|
Allowance for doubtful accounts |
|
| (13 | ) |
|
| (18 | ) |
|
| (12 | ) |
|
| (11 | ) |
Net accounts receivable |
| $ | 1,462 |
|
| $ | 1,356 |
|
| $ | 1,695 |
|
| $ | 1,670 |
|
|
|
Goodwill
Devon performs an annual impairment test of goodwill at October 31, or more frequently if events or changes in circumstances indicate that the carrying value of a reporting unit may not be recoverable. Sustained weakness in the overall energy sector driven by low commodity prices, together with a decline in EnLink’s unit price, caused a noncash goodwill impairment of $873 million in the first quarter of 2016. This consisted of a full impairment charge of $93 million related to EnLink’s Crude and Condensate reporting unit and partial impairments to EnLink’s Texas and General Partner reporting units of $473 million and $307 million, respectively.
Asset Divestitures
During the third quarter of 2016, Devon derecognized $197 million of goodwill in conjunction with the upstream oil and gas asset divestitures discussed in Note 2.
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Customer relationships |
| $ | 1,796 |
|
| $ | 1,796 |
|
Accumulated amortization |
|
| (202 | ) |
|
| (172 | ) |
Net intangibles |
| $ | 1,594 |
|
| $ | 1,624 |
|
The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $37 million and $29 million for the three months ended September 30, 2017 and 2016, respectively, and $96 million and $87 million for the nine months ended September 30, 2017 and 2016, respectively. The remaining amortization expense is estimated to be $123 million for each of the next five years.
|
|
Components of other current liabilities include the following:
| September 30, 2017 |
|
| December 31, 2016 |
| ||
| (Millions) |
| |||||
Installment payment - see Note 2 | $ | 243 |
|
| $ | 249 |
|
Accrued interest payable |
| 204 |
|
|
| 130 |
|
Income taxes payable |
| 197 |
|
|
| 32 |
|
Derivative liabilities |
| 54 |
|
|
| 187 |
|
Restructuring liabilities |
| 20 |
|
|
| 48 |
|
Other |
| 285 |
|
|
| 420 |
|
Other current liabilities | $ | 1,003 |
|
| $ | 1,066 |
|
|
|
A summary of debt is as follows:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Devon debt: |
|
|
|
|
|
|
|
|
Debentures and notes |
| $ | 6,933 |
|
| $ | 6,933 |
|
Net discount on debentures and notes |
|
| (30 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (41 | ) |
|
| (44 | ) |
Total Devon debt |
|
| 6,862 |
|
|
| 6,859 |
|
EnLink debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 74 |
|
|
| 148 |
|
Debentures and notes |
|
| 3,500 |
|
|
| 3,163 |
|
Net premium (discount) on debentures and notes |
|
| (6 | ) |
|
| 9 |
|
Debt issuance costs |
|
| (27 | ) |
|
| (25 | ) |
Total EnLink debt |
|
| 3,541 |
|
|
| 3,295 |
|
Total debt |
|
| 10,403 |
|
|
| 10,154 |
|
Less amount classified as short-term debt (1) |
|
| 20 |
|
|
| — |
|
Total long-term debt |
| $ | 10,383 |
|
| $ | 10,154 |
|
|
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
13.Property, Plant and Equipment
The following table presents the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
|
| March 31, 2018 |
|
| December 31, 2017 |
| ||
Property and equipment, at cost: |
|
|
|
|
|
|
|
|
Proved |
| $ | 47,685 |
|
| $ | 47,295 |
|
Unproved and properties under development |
|
| 2,478 |
|
|
| 2,457 |
|
Total oil and gas |
|
| 50,163 |
|
|
| 49,752 |
|
Less accumulated DD&A |
|
| (36,688 | ) |
|
| (36,434 | ) |
Oil and gas property and equipment, net |
|
| 13,475 |
|
|
| 13,318 |
|
EnLink midstream and other |
|
| 9,298 |
|
|
| 9,120 |
|
Devon midstream and other |
|
| 1,957 |
|
|
| 1,955 |
|
Less accumulated DD&A |
|
| (3,347 | ) |
|
| (3,222 | ) |
Midstream and other property and equipment, net |
|
| 7,908 |
|
|
| 7,853 |
|
Property and equipment, net |
| $ | 21,383 |
|
| $ | 21,171 |
|
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.
|
| March 31, 2018 |
|
| December 31, 2017 |
| ||
Customer relationships |
| $ | 1,796 |
|
| $ | 1,796 |
|
Accumulated amortization |
|
| (330 | ) |
|
| (299 | ) |
Net intangibles |
| $ | 1,466 |
|
| $ | 1,497 |
|
The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $31 million and $29 million for the three months ended March 31, 2018 and 2017, respectively. The remaining amortization expense is estimated to be $123 million for each of the next five years.
Components of other current liabilities include the following:
| March 31, 2018 |
|
| December 31, 2017 |
| ||
Derivative liabilities | $ | 350 |
|
| $ | 331 |
|
Installment payment |
| — |
|
|
| 250 |
|
Income taxes payable |
| 142 |
|
|
| 145 |
|
Accrued interest payable |
| 147 |
|
|
| 131 |
|
Restructuring liabilities |
| 18 |
|
|
| 19 |
|
Other |
| 340 |
|
|
| 325 |
|
Other current liabilities | $ | 997 |
|
| $ | 1,201 |
|
EnLink’s final installment payment relating to its acquisition of Anadarko Basin gathering and processing midstream assets in 2016 was paid in January 2018 using borrowings under EnLink’s credit facility.
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
A summary of debt is as follows:
|
| March 31, 2018 |
|
| December 31, 2017 |
| ||
Devon debt: |
|
|
|
|
|
|
|
|
8.25% due July 1, 2018 |
| $ | 20 |
|
| $ | 20 |
|
2.25% due December 15, 2018 |
|
| 95 |
|
|
| 95 |
|
6.30% due January 15, 2019 |
|
| 162 |
|
|
| 162 |
|
4.00% due July 15, 2021 |
|
| 500 |
|
|
| 500 |
|
3.25% due May 15, 2022 |
|
| 1,000 |
|
|
| 1,000 |
|
5.85% due December 15, 2025 |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 |
|
| 73 |
|
|
| 73 |
|
7.875% due September 30, 2031 (1) |
|
| 675 |
|
|
| 1,059 |
|
7.95% due April 15, 2032 (1) |
|
| 366 |
|
|
| 789 |
|
5.60% due July 15, 2041 |
|
| 1,250 |
|
|
| 1,250 |
|
4.75% due May 15, 2042 |
|
| 750 |
|
|
| 750 |
|
5.00% due June 15, 2045 |
|
| 750 |
|
|
| 750 |
|
Net discount on debentures and notes |
|
| (25 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (35 | ) |
|
| (39 | ) |
Total Devon debt |
|
| 6,066 |
|
|
| 6,864 |
|
EnLink and General Partner debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 447 |
|
|
| 74 |
|
2.70% due April 1, 2019 |
|
| 400 |
|
|
| 400 |
|
4.40% due April 1, 2024 |
|
| 550 |
|
|
| 550 |
|
4.15% due June 1, 2025 |
|
| 750 |
|
|
| 750 |
|
4.85% due July 15, 2026 |
|
| 500 |
|
|
| 500 |
|
5.60% due April 1, 2044 |
|
| 350 |
|
|
| 350 |
|
5.05% due April 1, 2045 |
|
| 450 |
|
|
| 450 |
|
5.45% due June 1, 2047 |
|
| 500 |
|
|
| 500 |
|
Net discount on debentures and notes |
|
| (6 | ) |
|
| (6 | ) |
Debt issuance costs |
|
| (25 | ) |
|
| (26 | ) |
Total EnLink and General Partner debt |
|
| 3,916 |
|
|
| 3,542 |
|
Total debt |
|
| 9,982 |
|
|
| 10,406 |
|
Less amount classified as short-term debt (2) |
|
| 354 |
|
|
| 115 |
|
Total long-term debt |
| $ | 9,628 |
|
| $ | 10,291 |
|
(1) | These senior notes were included in the 2018 tender offer repurchases discussed below. |
(2) | Short-term debt as of March 31, 2018 consists of Devon’s $20 million of 8.25% senior notes due July 1, 2018, $95 million of 2.25% senior notes due December 15, 2018 and $162 million of 6.30% senior notes due January 15, 2019 and $77 million of borrowings under the General Partner’s credit facility due March 7, 2019. |
Credit Lines
Devon has a $3.0 billion Senior Credit Facility. As of September 30, 2017,March 31, 2018, Devon had $59$51 million in outstanding letters of credit under the Senior Credit Facility. There were no outstanding borrowings under the Senior Credit Facility at September 30, 2017.March 31, 2018. The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. Under the terms of the credit agreement, total capitalization is adjusted to add back noncash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of September 30, 2017,March 31, 2018, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.9%26.2%.
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
In the thirdfirst quarter of 2016,2018, Devon completed tender offers to repurchase $1.2 billion$807 million in aggregate principal amount of debt securities, using proceeds fromcash on hand. This included $384 million of the asset divestitures discussed in Note 2.7.875% senior notes due September 30, 2031 and $423 million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million loss on early retirement of debt, primarily consisting of $82$304 million in cash retirement costs and other fees.$8 million of noncash charges. These costs, along with other minimal noncash charges associated with retiring the debt, are included in net financing costs in the consolidated comprehensive statements of earnings.
EnLink Debt
All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
EnLink has a $1.5 billion unsecured revolving credit facility. As of September 30, 2017,March 31, 2018, there were $9$10 million in outstanding letters of credit and no$370 million in outstanding borrowings at an average rate of 3.3% under the $1.5 billion credit facility. The General Partner has a $250 million secured revolving credit facility. As of September 30, 2017,March 31, 2018, the General Partner had $74$77 million in outstanding borrowings at an average rate of 3.2%3.5%. EnLink and the General Partner were in compliance with all financial covenants in their respective credit facilities as of September 30, 2017.
In the second quarter of 2017, EnLink issued $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.March 31, 2018.
Net Financing Costs
The following schedule includes the components of net financing costs.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 2018 |
|
| 2017 |
| ||
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
| $ | 97 |
|
| $ | 120 |
|
| $ | 292 |
|
| $ | 376 |
|
| $ | 96 |
|
| $ | 97 |
|
Early retirement of debt |
|
| — |
|
|
| 84 |
|
|
| — |
|
|
| 84 |
|
|
| 312 |
|
|
| — |
|
Capitalized interest |
|
| (19 | ) |
|
| (16 | ) |
|
| (53 | ) |
|
| (47 | ) |
|
| (18 | ) |
|
| (16 | ) |
Other |
|
| (1 | ) |
|
| 7 |
|
|
| (3 | ) |
|
| 18 |
|
|
| (3 | ) |
|
| 2 |
|
Total Devon net financing costs |
|
| 77 |
|
|
| 195 |
|
|
| 236 |
|
|
| 431 |
|
|
| 387 |
|
|
| 83 |
|
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
|
| 43 |
|
|
| 37 |
|
|
| 125 |
|
|
| 105 |
|
|
| 44 |
|
|
| 40 |
|
Interest accretion on deferred installment payment |
|
| 7 |
|
|
| 13 |
|
|
| 20 |
|
|
| 39 |
|
|
| 1 |
|
|
| 7 |
|
Early retirement of debt |
|
| — |
|
|
| — |
|
|
| (9 | ) |
|
| — |
| ||||||||
Other |
|
| — |
|
|
| (2 | ) |
|
| (2 | ) |
|
| (5 | ) |
|
| (1 | ) |
|
| (2 | ) |
Total EnLink net financing costs |
|
| 50 |
|
|
| 48 |
|
|
| 134 |
|
|
| 139 |
|
|
| 44 |
|
|
| 45 |
|
Total net financing costs |
| $ | 127 |
|
| $ | 243 |
|
| $ | 370 |
|
| $ | 570 |
|
| $ | 431 |
|
| $ | 128 |
|
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
15.17. Asset Retirement Obligations
The following table presents the changes in Devon’s asset retirement obligations.
|
| Nine Months Ended September 30, |
| |||||||||||||
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||
|
| (Millions) |
|
| 2018 |
|
| 2017 |
| |||||||
Asset retirement obligations as of beginning of period |
| $ | 1,272 |
|
| $ | 1,414 |
|
| $ | 1,152 |
|
| $ | 1,272 |
|
Liabilities incurred and assumed through acquisitions |
|
| 30 |
|
|
| 18 |
|
|
| 15 |
|
|
| 10 |
|
Liabilities settled and divested |
|
| (53 | ) |
|
| (310 | ) |
|
| (20 | ) |
|
| (13 | ) |
Revision of estimated obligation |
|
| (184 | ) |
|
| 70 |
|
|
| 23 |
|
|
| (184 | ) |
Accretion expense on discounted obligation |
|
| 47 |
|
|
| 58 |
|
|
| 16 |
|
|
| 17 |
|
Foreign currency translation adjustment |
|
| 29 |
|
|
| 26 |
|
|
| (13 | ) |
|
| 4 |
|
Asset retirement obligations as of end of period |
|
| 1,141 |
|
|
| 1,276 |
|
|
| 1,173 |
|
|
| 1,106 |
|
Less current portion |
|
| 41 |
|
|
| 46 |
|
|
| 32 |
|
|
| 39 |
|
Asset retirement obligations, long-term |
| $ | 1,100 |
|
| $ | 1,230 |
|
| $ | 1,141 |
|
| $ | 1,067 |
|
During the first quarter of 2017, Devon reduced its estimated asset retirement obligations by $184 million primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets.
During the first nine months of 2016, Devon reduced its asset retirement obligation by $285 million for those obligations that were assumed by purchasers of certain upstream U.S. assets. See Note 2 for additional details.
|
|
The following table presents the components of net periodic benefit cost for Devon’s pension and postretirement benefit plans.
|
| Pension Benefits |
|
| Postretirement Benefits |
| ||||||||||||||||||||||||||
|
| Three Months Ended |
|
| Nine Months Ended |
|
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| 2017 |
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| 2016 |
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| 2017 |
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| 2016 |
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| 2016 |
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| 2016 |
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Service cost |
| $ | 4 |
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| $ | 3 |
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| $ | 12 |
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| $ | 12 |
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| $ | — |
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| $ | — |
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| $ | — |
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| $ | — |
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Interest cost |
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| 11 |
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| 9 |
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| 32 |
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| 32 |
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| — |
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| — |
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| — |
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| — |
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Expected return on plan assets |
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| (14 | ) |
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| (14 | ) |
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| (41 | ) |
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| (40 | ) |
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Amortization of prior service cost (1) |
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| 1 |
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| 1 |
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| 2 |
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| — |
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| — |
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| (1 | ) |
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| (1 | ) |
Net actuarial loss (1) |
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| 5 |
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| 6 |
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| 14 |
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| 19 |
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| — |
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| — |
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| — |
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| — |
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Net periodic benefit cost (2) |
| $ | 6 |
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| $ | 5 |
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| $ | 18 |
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| $ | 25 |
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| $ | — |
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| $ | — |
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| $ | (1 | ) |
| $ | (1 | ) |
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(2) Net periodic benefit cost is a component of G&A in the accompanying consolidated comprehensive statements of earnings.
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Common Stock Issued
In January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2.
In February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.
2425
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table Pension Benefits Three Months Ended March 31, 2018 2017 Service cost $ 3 $ 4 Interest cost 10 11 Expected return on plan assets (14 ) (14 ) Amortization of prior service cost (1) — 1 Net actuarial loss (1) 4 4 Net periodic benefit cost (2) $ 3 $ 6 (1) These net periodic benefit costs were reclassified out of other comprehensive earnings. (2) The service cost component of net periodic benefit cost is included in G&A expense and the remaining components of net periodic benefit costs are included in Other expenses in the accompanying consolidated comprehensive statements of earnings. Devon announced a share-repurchase program to buy up to $1.0 billion of shares of common stock, which expires March 7, 2019. During the first quarter of 2018, Devon repurchased 2.6 million shares of common stock for $83 million, or $32.19 per share, under this program. Devon paid Amounts Rate (Millions) (Per Share) Quarter Ended 2017: First quarter 2017 $ 32 $ 0.06 Second quarter 2017 33 $ 0.06 Third quarter 2017 30 $ 0.06 Total year-to-date $ 95 Quarter Ended 2016: First quarter 2016 $ 125 $ 0.24 Second quarter 2016 33 $ 0.06 Third quarter 2016 32 $ 0.06 Total year-to-date $ 190 Subsidiary Equity Transactions As of EnLink has the ability to sell common units through its “at the market” equity offering programs. During the first three months of 2017, EnLink issued and sold 3 million common units through its programs and generated $55 million in net Distributions to Noncontrolling Interests EnLink and the General Partner distributed 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, Devon’s 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 Devon’s financial position or results of operations after consideration of recorded accruals. Actual amounts could differ materially from management’s estimates. DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) (Unaudited) Numerous oil and natural gas producers and related parties, including Devon, have been named in various lawsuits alleging royalty underpayments. Environmental Matters Devon is subject to certain environmental, health and safety laws and regulations, including with respect 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. Devon’s monetary exposure for environmental matters is not expected to be material. Other Matters Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject. The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables and accrued expenses included in the accompanying consolidated balance sheets approximated fair value at Fair Value Fair Value Measurements Using: Measurements Using: Carrying Total Fair Level 1 Level 2 Carrying Total Fair Level 1 Level 2 Amount Value Inputs Inputs Amount Value Inputs Inputs March 31, 2018 assets (liabilities): Cash equivalents $ 335 $ 335 $ 259 $ 76 Commodity derivatives $ 215 $ 215 $ — $ 215 Commodity derivatives $ (355 ) $ (355 ) $ — $ (355 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives �� $ (22 ) $ (22 ) $ — $ (22 ) Debt $ (9,982 ) $ (10,719 ) $ — $ (10,719 ) Capital lease obligations $ (4 ) $ (3 ) $ — $ (3 ) (Millions) September 30, 2017 assets (liabilities): December 31, 2017 assets (liabilities): Cash equivalents $ 1,510 $ 1,510 $ 1,431 $ 79 $ 1,533 $ 1,533 $ 1,454 $ 79 Commodity derivatives $ 43 $ 43 $ — $ 43 $ 211 $ 211 $ — $ 211 Commodity derivatives $ (60 ) $ (60 ) $ — $ (60 ) $ (294 ) $ (294 ) $ — $ (294 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (62 ) $ (62 ) $ — $ (62 ) $ (64 ) $ (64 ) $ — $ (64 ) Debt $ (10,403 ) $ (11,480 ) $ — $ (11,480 ) $ (10,406 ) $ (11,782 ) $ — $ (11,782 ) Installment payment $ (243 ) $ (244 ) $ — $ (244 ) $ (250 ) $ (250 ) $ — $ (250 ) Capital lease obligations $ (4 ) $ (4 ) $ — $ (4 ) $ (4 ) $ (3 ) $ — $ (3 ) December 31, 2016 assets (liabilities): Cash equivalents $ 1,542 $ 1,542 $ 1,298 $ 244 Commodity derivatives $ 10 $ 10 $ — $ 10 Commodity derivatives $ (203 ) $ (203 ) $ — $ (203 ) Interest rate derivatives $ 1 $ 1 $ — $ 1 Interest rate derivatives $ (41 ) $ (41 ) $ — $ (41 ) Debt $ (10,154 ) $ (10,760 ) $ — $ (10,760 ) Installment payment $ (473 ) $ (477 ) $ — $ (477 ) Capital lease obligations $ (7 ) $ (6 ) $ — $ (6 ) DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) (Unaudited) The following methods and assumptions were used to estimate the fair values in the table above. Level 1 Fair Value Measurements Cash equivalents – Amounts consist primarily of money market investments and U.S. and Canadian treasury securities. The fair value approximates the carrying value. Level 2 Fair Value Measurements Cash equivalents – Amounts consist primarily of commercial paper and Canadian agency and provincial securities investments. The fair value approximates the carrying value. Commodity and interest rate derivatives – The fair values of commodity and interest rate 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 – Devon’s 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 the credit facility balance is the carrying value. Installment payment – The fair value of the EnLink installment payment was based on Level 2 inputs from third-party market quotations. Capital lease obligations – The fair value was calculated using inputs from third-party banks. 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, Devon’s Canadian E&P operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged in oil and gas E&P activities. Devon considers EnLink, combined with the General Partner, to be an operating segment that is distinct from the U.S. and Canadian operating segments. EnLink’s 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. DEVON ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued) (Unaudited) U.S. Canada EnLink Eliminations Total U.S. Canada EnLink Eliminations Total (Millions) Three Months Ended September 30, 2017: Three Months Ended March 31, 2018: Revenues from external customers $ 1,575 $ 358 $ 1,223 $ — $ 3,156 $ 1,879 $ 319 $ 1,612 $ — $ 3,810 Asset dispositions and other $ 1 $ — $ (1 ) $ — $ — Intersegment revenues $ — $ — $ 149 $ (149 ) $ — Depreciation, depletion and amortization $ 305 $ 94 $ 138 $ — $ 537 Interest expense $ 247 $ 164 $ 44 $ (16 ) $ 439 Asset dispositions $ (12 ) $ — $ — $ — $ (12 ) Earnings (loss) before income taxes $ (100 ) $ (145 ) $ 64 $ — $ (181 ) Income tax expense (benefit) $ 1 $ (35 ) $ 6 $ — $ (28 ) Net earnings (loss) $ (101 ) $ (110 ) $ 58 $ — $ (153 ) Net earnings attributable to noncontrolling interests $ — $ — $ 44 $ — $ 44 Net earnings (loss) attributable to Devon $ (101 ) $ (110 ) $ 14 $ — $ (197 ) Property and equipment, net $ 10,538 $ 4,186 $ 6,659 $ — $ 21,383 Total assets $ 13,477 $ 5,271 $ 10,615 $ (47 ) $ 29,316 Capital expenditures, including acquisitions $ 612 $ 89 $ 181 $ — $ 882 Three Months Ended March 31, 2017: Revenues from external customers $ 2,081 $ 319 $ 1,151 $ — $ 3,551 Intersegment revenues $ — $ — $ 174 $ (174 ) $ — $ — $ — $ 171 $ (171 ) $ — Depreciation, depletion and amortization $ 195 $ 63 $ 142 $ — $ 400 $ 302 $ 98 $ 128 $ — $ 528 Interest expense $ 82 $ 17 $ 49 $ (15 ) $ 133 $ 80 $ 20 $ 45 $ (15 ) $ 130 Asset impairments $ — $ — $ 2 $ — $ 2 $ — $ — $ 7 $ — $ 7 Earnings before income taxes $ 167 $ 85 $ 20 $ — $ 272 Income tax expense $ (5 ) $ 28 $ 2 $ — $ 25 Net earnings $ 172 $ 57 $ 18 $ — $ 247 Net earnings attributable to noncontrolling interests $ — $ — $ 19 $ — $ 19 Net earnings (loss) attributable to Devon $ 172 $ 57 $ (1 ) $ — $ 228 Capital expenditures, including acquisitions $ 560 $ 103 $ 170 $ — $ 833 Three Months Ended September 30, 2016: Revenues from external customers $ 1,653 $ 305 $ 924 $ — $ 2,882 Asset dispositions and other $ 1,351 $ — $ — $ — $ 1,351 Intersegment revenues $ — $ — $ 180 $ (180 ) $ — Depreciation, depletion and amortization $ 196 $ 72 $ 126 $ — $ 394 Interest expense $ 185 $ 34 $ 49 $ (23 ) $ 245 Asset impairments $ 317 $ 2 $ — $ — $ 319 Restructuring and transaction costs $ (10 ) $ 5 $ — $ — $ (5 ) Earnings before income taxes $ 1,122 $ 37 $ 19 $ — $ 1,178 Asset dispositions $ (7 ) $ (1 ) $ 5 $ — $ (3 ) Earnings (loss) before income taxes $ 325 $ (12 ) $ 12 $ — $ 325 Income tax expense $ 5 $ 159 $ 7 $ — $ 171 $ 3 $ 2 $ 3 $ — $ 8 Net earnings (loss) $ 1,117 $ (122 ) $ 12 $ — $ 1,007 $ 322 $ (14 ) $ 9 $ — $ 317 Net earnings attributable to noncontrolling interests $ — $ — $ 14 $ — $ 14 $ — $ — $ 14 $ — $ 14 Net earnings (loss) attributable to Devon $ 1,117 $ (122 ) $ (2 ) $ — $ 993 $ 322 $ (14 ) $ (5 ) $ — $ 303 Capital expenditures, including acquisitions $ 277 $ 48 $ 132 $ — $ 457 Nine Months Ended September 30, 2017: Revenues from external customers $ 5,547 $ 951 $ 3,468 $ — $ 9,966 Asset dispositions and other $ 11 $ — $ (1 ) $ — $ 10 Intersegment revenues $ — $ — $ 515 $ (515 ) $ — Depreciation, depletion and amortization $ 556 $ 199 $ 407 $ — $ 1,162 Interest expense $ 243 $ 48 $ 133 $ (42 ) $ 382 Asset impairments $ — $ — $ 9 $ — $ 9 Earnings before income taxes $ 1,133 $ 126 $ 69 $ — $ 1,328 Income tax expense $ — $ 42 $ 9 $ — $ 51 Net earnings $ 1,133 $ 84 $ 60 $ — $ 1,277 Net earnings attributable to noncontrolling interests $ — $ — $ 59 $ — $ 59 Net earnings attributable to Devon $ 1,133 $ 84 $ 1 $ — $ 1,218 Property and equipment, net $ 7,726 $ 2,787 $ 6,569 $ — $ 17,082 $ 10,030 $ 4,078 $ 6,396 $ — $ 20,504 Total assets $ 13,302 $ 3,761 $ 10,548 $ (52 ) $ 27,559 $ 13,644 $ 4,869 $ 10,177 $ (55 ) $ 28,635 Capital expenditures, including acquisitions $ 1,460 $ 275 $ 636 $ — $ 2,371 $ 346 $ 82 $ 248 $ — $ 676 Nine Months Ended September 30, 2016: Revenues from external customers $ 4,320 $ 688 $ 2,488 $ — $ 7,496 Asset dispositions and other $ 1,351 $ — $ — $ — $ 1,351 Intersegment revenues $ — $ — $ 539 $ (539 ) $ — Depreciation, depletion and amortization $ 763 $ 284 $ 373 $ — $ 1,420 Interest expense $ 400 $ 101 $ 140 $ (66 ) $ 575 Asset impairments $ 2,810 $ 1,168 $ 873 $ — $ 4,851 Restructuring and transaction costs $ 245 $ 15 $ 6 $ — $ 266 Loss before income taxes $ (2,040 ) $ (1,359 ) $ (853 ) $ — $ (4,252 ) Income tax expense (benefit) $ (6 ) $ (223 ) $ 1 $ — $ (228 ) Net loss $ (2,034 ) $ (1,136 ) $ (854 ) $ — $ (4,024 ) Net earnings (loss) attributable to noncontrolling interests $ 1 $ — $ (392 ) $ — $ (391 ) Net loss attributable to Devon $ (2,035 ) $ (1,136 ) $ (462 ) $ — $ (3,633 ) Property and equipment, net $ 7,196 $ 2,778 $ 6,195 $ — $ 16,169 Total assets $ 12,317 $ 4,355 $ 10,197 $ (56 ) $ 26,813 Capital expenditures, including acquisitions $ 2,454 $ 158 $ 816 $ — $ 3,428 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis addresses material changes in our results of operations Overview of Key components of our financial performance as compared to prior quarter are summarized below. Three Months Ended September 30, Nine Months Ended September 30, (3) 2017 2016 Change 2017 2016 Change (Millions, except per share amounts) Q1 2018 (3) Q4 2017 (3) Change Net earnings (loss) attributable to Devon $ 228 $ 993 - 77 % $ 1,218 $ (3,633 ) N/M $ (197 ) $ 183 - 208 % Net earnings (loss) per diluted share attributable to Devon $ 0.43 $ 1.89 - 77 % $ 2.31 $ (7.22 ) N/M $ (0.38 ) $ 0.35 - 209 % Core earnings (loss) attributable to Devon (1) $ 242 $ 47 +415 % $ 636 $ (169 ) N/M Core earnings (loss) per diluted share attributable to Devon (1) $ 0.46 $ 0.09 +411 % $ 1.20 $ (0.34 ) N/M Core earnings attributable to Devon (1) $ 108 $ 199 - 46 % Core earnings per diluted share attributable to Devon (1) $ 0.20 $ 0.38 - 48 % Retained production (MBoe/d) 527 550 - 4 % 542 578 - 6 % 511 512 0 % Total production (MBoe/d) 527 577 - 9 % 542 635 - 15 % 544 548 - 1 % Realized price per Boe (2) $ 25.67 $ 20.98 +22 % $ 25.41 $ 17.37 +46 % $ 27.75 $ 27.59 +1 % Operating cash flow $ 776 $ 727 +7 % $ 2,420 $ 1,237 +96 % $ 804 $ 725 +11 % Capital expenditures, including acquisitions $ 833 $ 457 +82 % $ 2,371 $ 3,428 - 31 % Capitalized expenditures, including acquisitions $ 882 $ 840 +5 % Shareholder and noncontrolling interests distributions $ 114 $ 109 +5 % $ 342 $ 414 - 17 % $ 134 $ 139 - 4 % Cash and cash equivalents $ 2,781 $ 2,385 +17 % $ 1,424 $ 2,673 - 47 % Total debt $ 10,403 $ 11,354 - 8 % $ 9,982 $ 10,406 - 4 % (1) Core earnings (2) Excludes any impact of oil, gas and NGL derivatives. (3) Except for balance sheet amounts, which are presented as of During the first Maximize cash flow by optimizing base production and reducing per-unit cash costs; Improve capital efficiency with a concentration of investment on highest-returning development projects in the Delaware Basin and STACK; Simplify our portfolio by monetizing non-core assets; Improve financial strength by reducing debt; and Return cash to shareholders. During the first Reduced long-term debt by approximately $800 million using cash on hand. Authorized and began executing a $1.0 billion share-repurchase program. Announced the sale of our Johnson County assets for $553 million. Upon expected closing in the second quarter of 2018, divestiture proceeds associated with our 2020 Vision will reach approximately $1.1 billion since 2017. Increased our quarterly common stock dividends 33% to $0.08 per share beginning in the second quarter of 2018. Subsequent to quarter-end, we completed a workforce reduction and we continue other cost reduction initiatives expected to generate $110 million of annualized savings. 30 We exited the Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change Oil (MBbls/d) Barnett Shale 1 1 - 13 % 1 1 - 22 % Delaware Basin 31 31 +0 % 31 35 - 12 % Eagle Ford 30 33 - 10 % 38 44 - 15 % Heavy Oil 18 22 - 15 % 18 23 - 22 % Rockies Oil 12 11 +9 % 13 14 - 9 % STACK 27 21 +31 % 24 18 +34 % Other 11 11 + 4 % 10 12 - 17 % Retained assets 130 130 +0 % 135 147 - 8 % Divested assets — 6 N/M — 13 N/M Total 130 136 - 5 % 135 160 - 16 % Bitumen (MBbls/d) Heavy Oil 103 115 - 11 % 109 105 +4 % Gas (MMcf/d) Barnett Shale 672 730 - 8 % 677 752 - 10 % Delaware Basin 90 92 - 3 % 91 92 - 0 % Eagle Ford 88 85 +4 % 101 111 - 9 % Heavy Oil 16 18 - 11 % 17 20 - 14 % Rockies Oil 11 19 - 39 % 14 27 - 47 % STACK 313 292 +7 % 300 296 +1 % Other 11 13 - 16 % 12 14 - 16 % Retained assets 1,201 1,249 - 4 % 1,212 1,312 - 8 % Divested assets — 75 N/M — 165 N/M Total 1,201 1,324 - 9 % 1,212 1,477 - 18 % NGLs (MBbls/d) Barnett Shale 36 44 - 18 % 40 45 - 10 % Delaware Basin 11 12 - 14 % 10 12 - 19 % Eagle Ford 12 13 - 8 % 13 18 - 29 % Rockies Oil 1 1 +9 % 1 1 - 2 % STACK 32 23 +37 % 30 28 +7 % Other 2 3 - 10 % 2 3 - 13 % Retained assets 94 96 - 2 % 96 107 - 10 % Divested assets — 8 N/M — 17 N/M Total 94 104 - 10 % 96 124 - 22 % Combined (MBoe/d) Barnett Shale 148 166 - 11 % 154 171 - 10 % Delaware Basin 57 59 - 3 % 56 62 - 11 % Eagle Ford 57 61 - 7 % 67 81 - 17 % Heavy Oil 124 140 - 11 % 130 132 - 1 % Rockies Oil 16 16 +0 % 17 20 - 17 % STACK 111 92 +20 % 104 95 +9 % Other 14 16 - 8 % 14 17 - 17 % Retained assets 527 550 - 4 % 542 578 - 6 % Divested assets — 27 N/M — 57 N/M Total 527 577 - 9 % 542 635 - 15 % Three Months Ended September 30, Nine Months Ended September 30, 2017 (1) 2016 (1) Change 2017 (1) 2016 (1) Change Oil (per Bbl) U.S. $ 47.12 $ 42.51 +11 % $ 47.84 $ 36.89 +30 % Canada $ 35.02 $ 27.46 +28 % $ 32.77 $ 22.26 +47 % Total $ 45.41 $ 40.12 +13 % $ 45.83 $ 34.78 +32 % Bitumen (per Bbl) Canada $ 31.75 $ 23.00 +38 % $ 28.49 $ 17.77 +60 % Gas (per Mcf) U.S. $ 2.45 $ 2.24 +10 % $ 2.54 $ 1.70 +50 % NGLs (per Bbl) U.S. $ 15.15 $ 9.80 +55 % $ 14.62 $ 8.84 +65 % Combined (per Boe) U.S. $ 23.85 $ 20.26 +18 % $ 24.44 $ 17.16 +42 % Canada $ 31.59 $ 23.23 +36 % $ 28.50 $ 18.15 +57 % Total $ 25.67 $ 20.98 +22 % $ 25.41 $ 17.37 +46 % Three Months Ended September 30, Oil Bitumen Gas NGLs Total (Millions) 2016 sales $ 502 $ 244 $ 273 $ 94 $ 1,113 Change due to volumes (23 ) (26 ) (25 ) (9 ) (83 ) Change due to prices 63 83 23 46 215 2017 sales $ 542 $ 301 $ 271 $ 131 $ 1,245 Nine Months Ended September 30, Oil Bitumen Gas NGLs Total (Millions) 2016 sales $ 1,523 $ 512 $ 688 $ 300 $ 3,023 Change due to volumes (243 ) 16 (125 ) (68 ) (420 ) Change due to prices 407 319 279 152 1,157 2017 sales $ 1,687 $ 847 $ 842 $ 384 $ 3,760 The The Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (Millions) Cash settlements: Oil derivatives $ 11 $ 20 $ 29 $ (41 ) Gas derivatives 13 (4 ) 14 47 NGL derivatives — — — (2 ) Total cash settlements 24 16 43 4 Gains (losses) on fair value changes: Oil derivatives (157 ) 23 72 (7 ) Gas derivatives (7 ) 35 101 (26 ) NGL derivatives (4 ) 5 (2 ) (1 ) Total gains (losses) on fair value changes (168 ) 63 171 (34 ) Oil, gas and NGL derivatives $ (144 ) $ 79 $ 214 $ (30 ) Three Months Ended September 30, 2017 Oil Bitumen Gas NGLs Boe (Per Bbl) (Per Bbl) (Per Mcf) (Per Bbl) (Per Boe) Realized price without hedges $ 45.41 $ 31.75 $ 2.45 $ 15.15 $ 25.67 Cash settlements of hedges 0.96 — 0.12 (0.03 ) 0.52 Realized price, including cash settlements $ 46.37 $ 31.75 $ 2.57 $ 15.12 $ 26.19 �� Three Months Ended September 30, 2016 Oil Bitumen Gas NGLs Boe (Per Bbl) (Per Bbl) (Per Mcf) (Per Bbl) (Per Boe) Realized price without hedges $ 40.12 $ 23.00 $ 2.24 $ 9.80 $ 20.98 Cash settlements of hedges 1.56 — (0.04 ) 0.10 0.32 Realized price, including cash settlements $ 41.68 $ 23.00 $ 2.20 $ 9.90 $ 21.30 Nine Months Ended September 30, 2017 Oil Bitumen Gas NGLs Boe (Per Bbl) (Per Bbl) (Per Mcf) (Per Bbl) (Per Boe) Realized price without hedges $ 45.83 $ 28.49 $ 2.54 $ 14.62 $ 25.41 Cash settlements of hedges 0.80 — 0.05 (0.02 ) 0.29 Realized price, including cash settlements $ 46.63 $ 28.49 $ 2.59 $ 14.60 $ 25.70 Nine Months Ended September 30, 2016 Oil Bitumen Gas NGLs Boe (Per Bbl) (Per Bbl) (Per Mcf) (Per Bbl) (Per Boe) Realized price without hedges $ 34.78 $ 17.77 $ 1.70 $ 8.84 $ 17.37 Cash settlements of hedges (0.94 ) — 0.12 (0.06 ) 0.02 Realized price, including cash settlements $ 33.84 $ 17.77 $ 1.82 $ 8.78 $ 17.39 drivers following the graph. Upstream Operations Oil, Gas and NGL Production Q1 2018 % of Total Q4 2017 Change Oil and bitumen (MBbls/d) STACK 35 14 % 30 +20 % Delaware Basin 36 14 % 32 +13 % Rockies Oil 18 7 % 15 +17 % Heavy Oil 18 7 % 18 +1 % Eagle Ford 23 9 % 27 - 16 % Barnett Shale 1 0 % 1 +18 % Other 9 5 % 9 - 5 % Retained assets 140 56 % 132 +6 % Divested assets — 0 % — N/M Total Oil 140 56 % 132 +6 % Bitumen 111 44 % 114 - 3 % Total Oil and bitumen 251 246 +2 % Q1 2018 % of Total Q4 2017 Change Gas (MMcf/d) STACK 344 29 % 316 +9 % Delaware Basin 97 8 % 89 +9 % Rockies Oil 18 2 % 14 +27 % Heavy Oil 12 1 % 15 - 18 % Eagle Ford 63 5 % 87 - 27 % Barnett Shale 470 40 % 466 +1 % Other 10 1 % 13 - 27 % Retained assets 1,014 86 % 1,000 +1 % Divested assets 163 14 % 175 - 7 % Total 1,177 1,175 +0 % Q1 2018 % of Total Q4 2017 Change NGLs (MBbls/d) STACK 37 38 % 34 +7 % Delaware Basin 11 12 % 13 - 9 % Rockies Oil 2 2 % 1 +38 % Eagle Ford 8 8 % 13 - 41 % Barnett Shale 31 32 % 36 - 13 % Other 2 2 % 3 - 40 % Retained assets 91 94 % 100 - 9 % Divested assets 6 6 % 6 - 5 % Total 97 106 - 8 % Q1 2018 % of Total Q4 2017 Change Combined (MBoe/d) STACK 129 24 % 117 +11 % Delaware Basin 64 12 % 60 +7 % Rockies Oil 23 4 % 19 +20 % Heavy Oil 131 24 % 134 - 2 % Eagle Ford 41 8 % 55 - 25 % Barnett Shale 110 20 % 114 - 3 % Other 13 2 % 13 - 2 % Retained assets 511 94 % 512 - 0 % Divested assets 33 6 % 36 - 7 % Total 544 548 - 1 % Production declines reduced our upstream revenue by $15 million. Retained production results were highlighted by strong oil production in the STACK, Delaware Basin and Rockies, averaging 16% growth from prior quarter. These noted production gains were offset by reduced completion activity in the Eagle Ford. Oil, Gas and NGL Prices Q1 2018 Realization Q4 2017 Change Oil and bitumen (per Bbl) WTI index $ 62.93 $ 55.49 +13 % Access Western Blend index $ 35.44 $ 40.94 - 13 % U.S. $ 61.79 98% $ 54.18 +14 % Canada $ 19.74 31% $ 32.54 - 39 % Realized price, unhedged $ 40.15 64% $ 42.59 - 6 % Cash settlements $ (0.10 ) $ (0.38 ) Realized price, with hedges $ 40.05 64% $ 42.21 - 5 % Q1 2018 Realization Q4 2017 Change Gas (per Mcf) Henry Hub index $ 3.01 $ 2.93 +3 % Realized price, unhedged $ 2.41 80% $ 2.29 +5 % Cash settlements $ 0.17 $ 0.19 Realized price, with hedges $ 2.58 86% $ 2.48 +4 % Q1 2018 Realization Q4 2017 Change NGLs (per Bbl) Mont Belvieu blended index (1) $ 25.88 $ 28.61 - 10 % Realized price, unhedged $ 22.56 87% $ 18.46 +22 % Cash settlements $ (0.53 ) $ (0.30 ) Realized price, with hedges $ 22.03 85% $ 18.16 +21 % (1) Based upon composition of our NGL barrel. 32 Q1 2018 Q4 2017 Change Combined (per Boe) U.S. $ 30.39 $ 26.18 +16 % Canada $ 19.45 $ 31.95 - 39 % Realized price, unhedged $ 27.75 $ 27.59 +1 % Cash settlements $ 0.23 $ 0.19 Realized price, with hedges $ 27.98 $ 27.78 +1 % Oil, gas and NGL sales decreased $15 million primarily as a result of three pricing factors during the quarter. First, our U.S. oil revenues benefitted $70 million from a 13% increase in the average WTI index during the quarter. Second, the average realization in Canada was significantly lower than prior quarter due to export and pipeline constraints that reduced our revenues approximately $150 million. Third, as discussed inNote 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $62 million during the first quarter of 2018 with no impact to net earnings. Commodity Derivatives Q1 2018 Q4 2017 Change Q Oil $ (2 ) $ (8 ) +76 % Natural gas 18 21 - 13 % NGL (5 ) (3 ) - 68 % Total cash settlements 11 10 +7 % Valuation changes (52 ) (67 ) +22 % Total $ (41 ) $ (57 ) +28 % Cash settlements as presented in the tables above represent realized gains or losses related to In addition to cash settlements, we also recognize fair value changes on our oil, gas and NGL derivative instruments in each reporting period. The changes in fair value resulted from new positions and settlements that occurred during each period, as well as the Production Expenses Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change (Millions) Operating revenues $ 2,055 $ 1,690 +22 % $ 5,992 $ 4,503 +33 % Product purchases (1,721 ) (1,391 ) +24 % (5,043 ) (3,618 ) +39 % Operations and maintenance expenses (92 ) (89 ) +3 % (276 ) (266 ) +4 % Operating profit $ 242 $ 210 +15 % $ 673 $ 619 +9 % Devon loss $ (11 ) $ (18 ) +39 % $ (47 ) $ (37 ) -27 % EnLink profit 253 228 +11 % 720 656 +10 % Total profit $ 242 $ 210 +15 % $ 673 $ 619 +9 % Q1 2018 Q4 2017 Change LOE $ 241 $ 236 +2 % Gathering, processing & transportation 228 163 +40 % Production taxes 59 51 +16 % Property taxes 15 13 +15 % Total $ 543 $ 463 +17 % Per Boe: LOE $ 4.91 $ 4.68 +5 % Gathering, processing & transportation $ 4.65 $ 3.23 +44 % Percent of oil, gas and NGL sales: Production taxes 4.4 % 3.7 % +19 % Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change (Millions, except per Boe amounts) LOE: U.S. $ 256 $ 248 +3 % $ 761 $ 886 - 14 % Canada 135 107 +26 % 415 329 +26 % Total $ 391 $ 355 +10 % $ 1,176 $ 1,215 - 3 % LOE per Boe: U.S. $ 6.89 $ 6.17 +12 % $ 6.76 $ 6.42 +5 % Canada $ 11.81 $ 8.31 +42 % $ 11.70 $ 9.13 +28 % Total $ 8.05 $ 6.69 +20 % $ 7.95 $ 6.98 +14 % Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change (Millions) Gross G&A $ 196 $ 184 +7 % $ 623 $ 642 - 3 % Capitalized G&A (55 ) (54 ) +3 % (170 ) (183 ) - 7 % Reimbursed G&A (19 ) (19 ) +1 % (53 ) (66 ) - 20 % Devon Net G&A 122 111 +10 % 400 393 +2 % EnLink Net G&A 31 30 +2 % 98 89 +10 % Net G&A $ 153 $ 141 +8 % $ 498 $ 482 +3 % Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change (Millions) Production taxes $ 40 $ 39 +3 % $ 131 $ 110 +19 % Property and other taxes 20 19 +2 % 62 79 - 21 % Devon production and property taxes 60 58 +4 % 193 189 +2 % EnLink property taxes 11 9 +24 % 34 31 +7 % Production and property taxes $ 71 $ 67 +5 % $ 227 $ 220 +3 % Percentage of oil, gas and NGL sales: Production taxes 3.2 % 3.5 % - 8 % 3.5 % 3.6 % - 4 % Property and other taxes 2.5 % 2.6 % - 3 % 2.6 % 3.7 % - 30 % Total 5.7 % 6.1 % - 6 % 6.1 % 7.3 % - 17 % earnings. Production taxes increased Marketing & Midstream Operations Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change (Millions, except per Boe amounts) DD&A: Oil and gas properties $ 232 $ 239 - 3 % $ 675 $ 930 - 27 % Other assets 26 29 - 9 % 80 117 - 31 % Devon DD&A 258 268 - 4 % 755 1,047 - 28 % EnLink DD&A 142 126 +13 % 407 373 +9 % Total DD&A $ 400 $ 394 +2 % $ 1,162 $ 1,420 - 18 % DD&A per Boe: Oil and gas properties $ 4.78 $ 4.51 +6 % $ 4.56 $ 5.35 - 15 % Q1 2018 Q4 2017 Change Operating revenues $ 1,761 $ 1,756 +0 % Product purchases (1,381 ) (1,374 ) +1 % Operations and maintenance expenses (109 ) (110 ) - 1 % EnLink margin 271 272 - 0 % Devon margin 6 — N/M Total $ 277 $ 272 +2 % Exploration Expenses Q1 2018 Q4 2017 Change Unproved impairments $ 8 $ 137 - 94 % Geological and geophysical 10 17 - 41 % Exploration overhead and other 15 17 - 12 % Total $ 33 $ 171 - 81 % Unproved impairments primarily relate to a Depreciation, Depletion and Amortization Q1 2018 Q4 2017 Change Oil and gas per Boe $ 7.63 $ 7.14 +7 % Oil and gas $ 374 $ 360 +4 % Midstream and other assets 25 30 - 14 % Devon 399 390 +2 % EnLink 138 138 - 0 % Total $ 537 $ 528 +2 % Our oil and gas DD&A remained relatively flat as compared to the prior period. Increases in oil and gas DD&A rates were due to continued development in the STACK and Delaware Basin. 33 Table of Financing Costs, net Financing costs, Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 Change 2017 2016 Change (Millions) Devon net financing costs: Interest based on debt outstanding $ 97 $ 120 - 19 % $ 292 $ 376 - 22 % Early retirement of debt — 84 N/M — 84 N/M Capitalized interest (19 ) (16 ) +21 % (53 ) (47 ) +12 % Other (1 ) 7 - 114 % (3 ) 18 - 117 % Total Devon net financing costs 77 195 - 60 % 236 431 - 45 % EnLink net financing costs: Interest based on debt outstanding 43 37 +16 % 125 105 +19 % Interest accretion on deferred installment payment 7 13 - 46 % 20 39 - 49 % Early retirement of debt — — N/M (9 ) — N/M Other — (2 ) N/M (2 ) (5 ) - 60 % Total EnLink net financing costs 50 48 +2 % 134 139 - 3 % Total net financing costs $ 127 $ 243 - 48 % $ 370 $ 570 - 35 % Income Taxes Q1 2018 Q4 2017 Current expense $ 4 $ 41 Deferred benefit (32 ) (245 ) Total benefit $ (28 ) $ (204 ) Effective income tax rate 15 % (203 %) For discussion on income taxes, see Note 8 in “Part I. Financial Information – Item 1. Financial Statements” in this report. 34 Results of Operations – Q1 2018 vs. Q1 2017 The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Specifically, the graph below shows the change in net earnings from the three months ended March 31, 2017 to the three months ended March 31, 2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Additional information regarding noncontrolling interests is discussed in Note 20 in “Part I. Financial Information – Item 1. Financial Statements” of this report. The graph below presents the drivers of the upstream operations change presented above, with additional details and discussion of the drivers following the graph. 35 Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 2017 2016 (Millions) Current income tax expense $ 39 $ 85 $ 71 $ 72 Deferred income tax expense (benefit) (14 ) 86 (20 ) (300 ) Total income tax expense (benefit) $ 25 $ 171 $ 51 $ (228 ) Effective income tax rate 9 % 15 % 4 % 5 % Upstream Operations Oil, Gas and NGL Production Q1 2018 % of Total Q1 2017 Change Oil and bitumen (MBbls/d) STACK 35 14 % 21 +68 % Delaware Basin 36 14 % 30 +21 % Rockies Oil 18 7 % 13 +38 % Heavy Oil 18 7 % 18 - 1 % Eagle Ford 23 9 % 46 - 51 % Barnett Shale 1 0 % 1 - 21 % Other 9 5 % 11 - 21 % Retained assets 140 56 % 140 - 0 % Divested assets — 0 % 2 - 100 % Total oil 140 56 % 142 - 1 % Bitumen 111 44 % 119 - 7 % Total oil and bitumen 251 261 - 4 % Q1 2018 % of Total Q1 2017 Change Gas (MMcf/d) STACK 344 29 % 287 +20 % Delaware Basin 97 8 % 87 +12 % Rockies Oil 18 2 % 15 +22 % Heavy Oil 12 1 % 23 - 46 % Eagle Ford 63 5 % 115 - 45 % Barnett Shale 470 40 % 498 - 6 % Other 10 1 % 12 - 17 % Retained assets 1,014 86 % 1,037 - 2 % Divested assets 163 14 % 191 - 14 % Total 1,177 1,228 - 4 % Q1 2018 % of Total Q1 2017 Change NGLs (MBbls/d) STACK 37 38 % 26 +41 % Delaware Basin 11 12 % 10 +20 % Rockies Oil 2 2 % 1 +71 % Eagle Ford 8 8 % 15 - 47 % Barnett Shale 31 32 % 36 - 12 % Other 2 2 % 2 - 13 % Retained assets 91 94 % 90 +2 % Divested assets 6 6 % 8 - 24 % Total 97 98 - 0 % Q1 2018 % of Total Q1 2017 Change Combined (MBoe/d) STACK 129 24 % 95 +36 % Delaware Basin 64 12 % 54 +18 % Rockies Oil 23 4 % 17 +38 % Heavy Oil 131 24 % 141 - 7 % Eagle Ford 41 8 % 80 - 49 % Barnett Shale 110 20 % 120 - 8 % Other 13 2 % 14 - 10 % Retained assets 511 94 % 521 - 2 % Divested assets 33 6 % 42 - 21 % Total 544 563 - 3 % Production declines reduced our upstream revenues by $38 million due to reduced completion activity in the Eagle Ford and natural production declines in the Barnett Shale. These decreases were partially offset by our focused development activities in the STACK, Delaware Basin and Rockies, where we saw production increases averaging 30% from Q1 2017. Oil, Gas and NGL Prices Q1 2018 Realization Q1 2017 Change Oil and bitumen (per Bbl) WTI index $ 62.93 $ 52.00 +21 % Access Western Blend index $ 35.44 $ 35.16 +1 % U.S. $ 61.79 98% $ 49.65 +24 % Canada $ 19.74 31% $ 26.30 - 25 % Realized price, unhedged $ 40.15 64% $ 37.33 +8 % Cash settlements $ (0.10 ) $ 0.50 Realized price, with hedges $ 40.05 64% $ 37.83 +6 % Q1 2018 Realization Q1 2017 Change Gas (per Mcf) Henry Hub index $ 3.01 $ 3.32 - 9 % Realized price, unhedged $ 2.41 80% $ 2.68 - 10 % Cash settlements $ 0.17 $ (0.03 ) Realized price, with hedges $ 2.58 86% $ 2.65 - 3 % Q1 2018 Realization Q1 2017 Change NGLs (per Bbl) Mont Belvieu blended index (1) $ 25.88 $ 23.93 +8 % Realized price, unhedged $ 22.56 87% $ 15.46 +46 % Cash settlements $ (0.53 ) $ — Realized price, with hedges $ 22.03 85% $ 15.46 +42 % 36 Q1 2018 Q1 2017 Change Combined (per Boe) U.S. $ 30.39 $ 25.86 +18 % Canada $ 19.45 $ 25.73 - 24 % Realized price, unhedged $ 27.75 $ 25.82 +7 % Cash settlements $ 0.23 $ 0.15 Realized price, with hedges $ 27.98 $ 25.97 +8 % Upstream revenues increased $89 million as a result of higher unhedged, realized prices for our oil and NGLs. The increase in oil sales primarily resulted from higher average WTI crude index prices, which were 21% higher in 2018. Additionally, NGL prices improved 8% at the Mont Belvieu, Texas hub compared to Q1 2017. Slightly offsetting these increases were widening oil and bitumen differentials in Canada due to export and pipeline constraints. Gas prices were lower due to lower North American regional index prices upon which our gas sales are based. As further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 the presentation of certain processing arrangements changed from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $62 million during the first quarter of 2018 with no impact to net earnings. Commodity Derivatives Q1 2018 Q1 2017 Change Oil $ (2 ) $ 12 - 117 % Natural gas 18 (4 ) +550 % NGL (5 ) — N/M Total cash settlements 11 8 +38 % Valuation changes (52 ) 224 - 123 % Total $ (41 ) $ 232 - 118 % Production Expenses Q1 2018 Q1 2017 Change LOE $ 241 $ 223 +8 % Gathering, processing & transportation 228 163 +40 % Production taxes 59 55 +7 % Property taxes 15 16 - 6 % Total $ 543 $ 457 +19 % Per Boe: LOE $ 4.91 $ 4.41 +11 % Gathering, processing & transportation $ 4.65 $ 3.21 +45 % Percent of oil, gas and NGL sales: Production taxes 4.4 % 4.2 % +4 % Gathering, processing and transportation expense increased $65 million primarily due to the presentation of certain processing arrangements changing from a net to a gross presentation. The change resulted in an increase to our upstream revenues and production expenses by $62 million during the first quarter of 2018 with no impact to net earnings. Marketing & Midstream Operations Q1 2018 Q1 2017 Change Operating revenues $ 1,761 $ 1,322 +33 % Product purchases (1,381 ) (1,002 ) +38 % Operations and maintenance expenses (109 ) (104 ) +5 % EnLink margin 271 216 +25 % Devon margin 6 (20 ) - 130 % Total $ 277 $ 196 +42 % The overall increase in marketing and midstream operating margin was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities. As further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report, in 2018 EnLink’s marketing and midstream revenues decreased by $138 million with a corresponding decrease to marketing and midstream expenses as a result of complying with the new revenue recognition accounting standard. Devon EnLink Consolidated 2017 2016 2017 2016 2017 2016 (Millions) Operating cash flow $ 1,892 $ 724 $ 528 $ 513 $ 2,420 $ 1,237 Divestitures of property and equipment 321 1,884 2 5 323 1,889 Issuance of common stock — 1,469 — — — 1,469 Proceeds from sale of investment — — 190 — 190 — Capital expenditures (1,541 ) (1,235 ) (662 ) (424 ) (2,203 ) (1,659 ) Acquisitions of property, equipment and businesses (39 ) (849 ) — (792 ) (39 ) (1,641 ) Debt activity, net — (1,946 ) 252 178 252 (1,768 ) Payment of installment payable — — (250 ) — (250 ) — Shareholder and noncontrolling interests distributions (95 ) (190 ) (247 ) (224 ) (342 ) (414 ) EnLink and General Partner distributions 199 199 (199 ) (199 ) — — Issuance of subsidiary units — — 486 835 486 835 Effect of exchange rate and other (45 ) (23 ) 30 150 (15 ) 127 Net change in cash and cash equivalents $ 692 $ 33 $ 130 $ 42 $ 822 $ 75 Cash and cash equivalents at end of period $ 2,639 $ 2,325 $ 142 $ 60 $ 2,781 $ 2,385 Exploration Expenses Q1 2018 Q1 2017 Change Unproved impairments $ 8 $ 41 - 80 % Geological and geophysical 10 42 - 76 % Exploration overhead and other 15 12 +25 % Total $ 33 $ 95 - 65 % Unproved impairments primarily relate to a portion of acreage in our U.S. non-core operations upon which we do not intend to pursue further exploration and development. Geological and geophysical costs decreased primarily in the STACK and Delaware Basin as we move into full-scale development. Q1 2018 Q1 2017 Change Oil and gas per Boe $ 7.63 $ 7.35 +4 % Oil and gas $ 374 $ 372 +1 % Midstream and other assets 25 28 - 9 % Devon 399 400 - 0 % EnLink 138 128 +8 % Total $ 537 $ 528 +2 % Financing Costs, net Financing costs, net increased $303 million primarily as a result of our $800 million early debt retirement in 2018. For additional information on our debt and related expenses, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report. 37 Capital Resources, Uses and Liquidity Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the three months ended March 31, 2018 and 2017. Devon EnLink Consolidated 2018 2017 2018 2017 2018 2017 Operating cash flow $ 610 $ 569 $ 194 $ 177 $ 804 $ 746 Divestitures of property and investments 47 32 1 190 48 222 EnLink and General Partner distributions 67 66 (67 ) (66 ) — — Capital expenditures (651 ) (397 ) (181 ) (256 ) (832 ) (653 ) Acquisitions of property and equipment (6 ) (20 ) — — (6 ) (20 ) Debt activity, net (1,111 ) — 122 (24 ) (989 ) (24 ) Shareholder and noncontrolling interests distributions (32 ) (32 ) (102 ) (81 ) (134 ) (113 ) Repurchases of common stock (71 ) — — — (71 ) — Subsidiary unit transactions — — 1 55 1 55 Effect of exchange rate and other (53 ) (61 ) 18 8 (35 ) (53 ) Net change in cash, cash equivalents and restricted cash $ (1,200 ) $ 157 $ (14 ) $ 3 $ (1,214 ) $ 160 Cash, cash equivalents and restricted cash at end of period $ 1,453 $ 2,104 $ 17 $ 15 $ 1,470 $ 2,119 Devon Sources and Uses of Cash Operating Cash Flow Net cash provided by operating activities increased 7% primarily due to higher commodity prices as compared to the first quarter of 2017. Our operating cash flow funded 94% of our capital expenditures during the first quarter of 2018. Our operating cash flow funded 94% of Nine Months Ended September 30, 2017 2016 (Millions) Oil and gas $ 1,480 $ 1,212 Corporate and other 61 23 Devon capital expenditures 1,541 1,235 EnLink capital expenditures 662 424 Total capital expenditures $ 2,203 $ 1,659 Devon acquisitions 39 849 EnLink acquisitions — 792 Total acquisitions $ 39 $ 1,641 Amounts Rate (Millions) (Per Share) Quarter Ended 2017: First quarter 2017 $ 32 $ 0.06 Second quarter 2017 33 $ 0.06 Third quarter 2017 30 $ 0.06 Total year-to-date $ 95 Quarter Ended 2016: First quarter 2016 $ 125 $ 0.24 Second quarter 2016 33 $ 0.06 Third quarter 2016 32 $ 0.06 Total year-to-date $ 190 Operating Cash Flow Net cash provided by operating activities increased 7% primarily due to higher commodity prices as compared to the first quarter of 2017. Our operating cash flow funded 94% of our capital expenditures during the first quarter of 2018. Divestitures of Property and Equipment During the first three months of 2018, as part of our announced divestiture program, we sold non-core U.S. assets for approximately $47 million, net of customary purchase price adjustments. EnLink and General Partner Distributions Devon received $67 million and $66 million in distributions from EnLink and the General Partner during the first three months of 2018 and 2017, respectively. Capital Expenditures and Acquisitions of Property and Equipment The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods. Q1 2018 Q1 2017 Oil and gas $ 626 $ 383 Corporate and other 25 14 Total capital expenditures 651 397 Acquisitions $ 6 $ 20 Capital expenditures consist of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Devon’s 2018 objectives are to concentrate capital spend in the STACK and Delaware Basin, while investing within cash flow and maintaining significant flexibility. Our capital investment program is driven by a disciplined 38 allocation process focused on returns. Our capital expenditures are higher in 2018 due to our continued development in the STACK and Delaware Basin. Debt Activity During the first quarter of 2018, our debt decreased $807 million due to completed tender offers of certain long-term debt. In conjunction with the tender offers, we recognized a $312 million loss on the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” in this report. Shareholder Distributions and Stock Activity Devon paid $32 million, or $0.06 per share, in common stock dividends during the first three months of 2018 and 2017. Devon announced an increase to its quarterly dividend to $0.08 per share beginning in the second quarter of 2018. In March 2018, we announced a share-repurchase program to buy up to $1.0 billion of shares of common stock, which expires March 7, 2019. Including unsettled shares, we repurchased 2.6 million shares of common stock for $83 million, or $32.19 per share through March 31, 2018. EnLink Sources and Uses of Cash EnLink’s operating cash flow has increased $17 million as a result of its continued development activities. Capital expenditures for EnLink’s midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. EnLink’s capital expenditures are lower in 2018 primarily due to lower capital expenditure levels for expansion projects. During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion of the $250 million installment payment related to EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets. During the first quarter of 2018, EnLink’s consolidated net debt borrowings increased $122 million. The increase was partially due to EnLink’s increased credit facility borrowings to fund growth capital expenditures and was partially offset by the payment of the remaining portion of the deferred installment payment related to its acquisition of Anadarko Basin gathering and processing midstream assets. During the first quarter of 2017, EnLink’s consolidated net debt borrowings decreased $24 million. The decrease was partially due to EnLink’s payment of a portion of the deferred installment payment related to its acquisition of Anadarko Basin gathering and processing midstream assets and was partially offset by increased credit facility borrowings to fund growth capital expenditures. EnLink and the General Partner distributed $102 million and $81 million to non-Devon unitholders during the first three months of 2018 and 2017, respectively. During the first quarter 2017, EnLink issued and sold 3 million common units and generated $55 million in net proceeds, through its “at the market” programs. During the first three months of 2018, EnLink issued and sold an immaterial amount of common units through its “at the market” programs. Devon Liquidity Our primary sources of capital and liquidity are our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity also include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. We estimate the combination of these sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments, share repurchases and other contractual commitments as discussed in this section. 39 Our operating cash flow is sensitive to many variables, the most volatile of which are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a portion of our production against downside price risk. We target hedging approximately 50% of our production in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. For additional information on our derivative positions in place at Divestitures of Property and Equipment To further focus our resource-rich portfolio, we are targeting asset divestiture proceeds in excess of $5 billion. In In a Overall, these two Barnett transactions, combined with other asset sales previously disclosed, will generate $1.1 billion of total divestiture proceeds. We are also marketing approximately $1 billion of Capital Expenditures Q2 2018 - Q4 2018 Full Year 2018 (Billions) Exploration and production $1.5 — $1.7 $2.2 — $2.4 Total Devon $1.6 — $1.9 $2.3 — $2.6 Credit Availability We have a $3.0 billion Senior Credit Facility. As of Debt Ratings We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items, including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and near-term and long-term production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. 40 There are no “rating triggers” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should a debt rating fall below a specified level. However, these downgrades could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future. Common Stock Repurchase Program In January 2018, EnLink paid the final $250 million installment payment related to the 2016 Anadarko Basin gathering and processing midstream assets acquisition. Critical Accounting Estimates Income Taxes Absent unexpected events and Non-GAAP Measures We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share attributable to Devon” in “Overview of 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. 41 Below are reconciliations of our core earnings Three Months Ended September 30, Nine Months Ended September 30, Before tax After tax After Noncontrolling Interests Per Share Before tax After tax After Noncontrolling Interests Per Share (Millions, except per share amounts) 2017 Earnings attributable to Devon (GAAP) $ 272 $ 247 $ 228 $ 0.43 $ 1,328 $ 1,277 $ 1,218 $ 2.31 Adjustments: Fair value changes in financial instruments and foreign currency 106 40 39 0.08 (292 ) (233 ) (232 ) (0.44 ) Gains and losses on asset sales 1 1 — — (6 ) (4 ) (4 ) (0.01 ) Asset impairments 2 1 1 — 9 7 4 0.01 Early retirement of debt — — — — (9 ) (7 ) (4 ) (0.01 ) Deferred tax asset valuation allowance — (26 ) (26 ) (0.05 ) — (346 ) (346 ) (0.66 ) Core earnings attributable to Devon (Non-GAAP) $ 381 $ 263 $ 242 $ 0.46 $ 1,030 $ 694 $ 636 $ 1.20 2016 Earnings (loss) attributable to Devon (GAAP) $ 1,178 $ 1,007 $ 993 $ 1.89 $ (4,252 ) $ (4,024 ) $ (3,633 ) $ (7.22 ) Adjustments: Fair value changes in financial instruments and foreign currency (16 ) (3 ) (3 ) (0.01 ) 201 91 86 0.17 Asset impairments 319 202 202 0.38 4,851 3,492 3,076 6.12 Restructuring and transaction costs (5 ) (3 ) (3 ) (0.01 ) 266 171 169 0.33 Gains on asset sales (1,351 ) (787 ) (787 ) (1.48 ) (1,351 ) (787 ) (787 ) (1.56 ) Early retirement of debt 84 53 53 0.10 84 53 53 0.11 Deferred tax asset valuation allowance — (408 ) (408 ) (0.78 ) — 867 867 1.71 Core earnings (loss) attributable to Devon (Non-GAAP) $ 209 $ 61 $ 47 $ 0.09 $ (201 ) $ (137 ) $ (169 ) $ (0.34 ) Before tax After tax After Noncontrolling Interests Per Diluted Share 2018 Loss attributable to Devon (GAAP) $ (181 ) $ (153 ) $ (197 ) $ (0.38 ) Adjustments: Asset dispositions (12 ) (9 ) (9 ) (0.02 ) Asset and exploration impairments 10 7 7 0.01 Deferred tax asset valuation allowance — 6 6 0.01 Fair value changes in financial instruments and foreign currency 63 62 61 0.12 Early retirement of debt 312 240 240 0.46 Core earnings attributable to Devon (Non-GAAP) $ 192 $ 153 $ 108 $ 0.20 2017 Earnings attributable to Devon (GAAP) $ 325 $ 317 $ 303 $ 0.58 Adjustments: Asset dispositions (3 ) (1 ) (3 ) (0.01 ) Asset and exploration impairments 48 32 29 0.06 Deferred tax asset valuation allowance — (101 ) (101 ) (0.19 ) Fair value changes in financial instruments and foreign currency (251 ) (163 ) (160 ) (0.31 ) Core earnings attributable to Devon (Non-GAAP) $ 119 $ 84 $ 68 $ 0.13 42 Item 3. Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk As of The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At Interest Rate Risk As of As of 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% unfavorable change in the Canadian-to-U.S. dollar exchange rate would not have materially impacted our Our non-Canadian foreign subsidiaries have a U.S. dollar functional currency. However, certain of our subsidiaries hold Canadian-dollar cash and engage in 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. 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 Devon’s financial reports and to other members of senior management and the Board of Directors. 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 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 We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject. Please see our There have been no material changes to the information included in Item 1A. “Risk Factors” in our 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 Period Total Number of Shares Purchased (1) Average Price Paid per Share July 1 - July 31 48,112 $ 32.08 August 1 - August 31 16,504 $ 31.69 September 1 - September 30 1,108 $ 31.81 Total 65,724 $ 31.97 Period Total Number of Shares Purchased (2) Average Price Paid per Share Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (1) Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (1) January 1 - January 31 16 $ 42.83 — — February 1 - February 28 547 $ 35.75 — — March 1 - March 31 2,822 $ 32.04 2,561 $ 917 Total 3,385 $ 32.69 2,561 (1) (2) In addition to shares purchased under the share repurchase program described above, these amounts also included 824,000 shares received by us from employees for the payment of personal income tax withholding on vesting transactions. Under the Devon Plan, eligible employees may purchase shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately Similarly, 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. Shares sold under the Canadian Plan were acquired 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 Item 3. Defaults Upon Senior Securities Not applicable. Item 4. Mine Safety Disclosures Not applicable. Not applicable. 44 Exhibit Number Description 4.1 Fourth Supplemental Indenture, dated March 22, 2018, among Devon Energy Corporation and The Bank of New York Mellon Trust Company, N.A. (as successor to The Bank of New York), as trustee, to the Indenture, dated as of March 1, 2002, among Devon Energy Corporation and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 to Devon Energy Corporation’s Form 8-K, filed on March 22, 2018; File No. 001-32318). 10.1 10.2 31.1 31.2 32.1 32.2 101.INS XBRL Instance Document. 101.SCH XBRL Taxonomy Extension Schema Document. 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document. 101.DEF XBRL Taxonomy Extension Definition Linkbase Document. 101.LAB XBRL Taxonomy Extension Labels Linkbase Document. 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document. _______________ *Indicates management contract or compensatory plan or arrangement. 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: /s/ Jeremy D. Humphers Jeremy D. Humphers Senior Vice President and Chief Accounting Officer 46Dividendsbelow summarizespresents the dividends components of net periodic benefit cost for Devon’s pension. There were no net periodic benefit cost for postretirement benefit plans for all periods presented below.on its common stock.In response to the depressed commodity price environment, Devon reduced its quarterly dividend tostock dividends of $32 million, or $0.06 per share, in the first three months of 2018 and 2017, respectively. Additionally, Devon announced a 33% increase to its quarterly dividend beginning in the second quarter of 2016.2018.EnLink has the ability to sell common units through its “at the market” equity offering programs. In the third quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common units through its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During the first nine months of 2017, EnLink issued and sold 5 million common units through its programs and generated $92 million in net proceeds.In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceeds of approximately $394 million.During the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million. In conjunction with its acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016, EnLink issued preferred units as discussed in Note 2.September 30, 2017,March 31, 2018, Devon’s ownership interest in EnLink was 23%, excluding the interest held by the General Partner. Devon’s controlling ownership interest in the General Partner as of September 30, 2017March 31, 2018 was 64%. Thegains and losses and related income taxes resulting from these transactions have been recorded as an adjustment to equity, with the change in ownership reflected as an adjustment to noncontrolling interests.proceeds.$247$102 million and $224$81 million to non-Devon unitholders during the first ninethree months of 2018 and 2017, and 2016, respectively.2526TheDevon is currently named as a defendant in a number of such lawsuits, including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the allegations typically asserted in these suits allegeare claims that the producers and related partiesDevon 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 is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does not currently believe that it is subject to material exposure with respect to such royalty matters.September 30, 2017March 31, 2018 and December 31, 2016.2017. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items is provided in Note 56 and Note 12,14, respectively.262727282829and capital resources and uses for the three-month and nine-month periodsperiod ended September 30, 2017March 31, 2018 compared to the three-month and nine-monthprevious periods ended September 30, 2016 and in our financial condition and liquidity since December 31, 2016.2017. For information regarding our critical accounting policies and estimates, see our 20162017 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”20172018 Results(loss) and core earnings (loss) per diluted share attributable to Devon are financial measures not prepared in accordance with GAAP. For a description of core earnings (loss) and core earnings (loss) per diluted share attributable to Devon, as well as reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.September 30.period end.ninethree months of 2017,2018, we generated solid operating results with our three-fold strategy of operating in North America’s best resource plays, delivering superior execution and maintaining a high degree of financial strength. Led by our development in the STACK and Delaware Basin, we continued to improve our 90-day initial production rates. With investments in proprietary data tools, predictive analytics and artificial intelligence, we are delivering industry-leading, initial-rate well productivity performance and improving the performance of our established wells. Even though our 2017 production volumes have declined from 2016 due to reduced capital investment, we estimate our highest-margin U.S. oil production from retained assets will exit 2017 at levels approximately 20% higher than year-end 2016.ComparedWe continue to 2016, commodity prices increased significantlyfocus on our “2020 Vision,” which is our plan through the end of the decade intended to optimize returns and were the primary driver for improvements in Devon’s operating margins, earnings anddeliver top-tier, capital-efficient cash flow duringgrowth. Our 2020 Vision is focused on the following strategic priorities:ninethree months of 2018, we made several strides to achieve our 2020 Vision and enhance shareholder value. Specifically, we had several key achievements:thirdfirst quarter of 20172018 with liquidity comprised of $2.8$1.4 billion of cash and $2.9 billion of available credit under our Senior Credit Facility. We have no significant debt maturities until 2021. At September 30, 2017, we also hadWe currently have approximately 65%60% of our remaining 2017 forecastedexpected oil and gas production hedged at an average floor priceprotected for the remainder of $50/Bbl2018. These contracts consist of collars and approximately 66% of our remaining 2017 forecastedswaps based off the WTI oil benchmark and the Henry Hub natural gas production hedged atindex. Additionally, we have entered into regional basis swaps in an average flooreffort to protect price of $3.10/MMBtu.realizations across our portfolio in the U.S. and Canada, including Western Canadian Select and Midland Sweet basis oil hedges. We are building our 2018 and 2019 hedge positions at similarmarket prices.We expect to further enhance our financial strength with our announced $1 billion asset divestiture program. The planned divestitures include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, we have closed non-core divestitures totaling approximately $400 million under this program.29We recently unveiled our “2020 Vision,” which is a strategic plan through the end of the decade intended to deliver top-tier returns on invested capital, while delivering sustainable, long-term growth for our business. We plan to attain leading returns with our 2020 Vision by pursing the following objectives:1.Disciplined capital allocation that builds scale in the STACK and Delaware Basin.2.Maximize returns by growing higher-value liquids production and lowering operating expenses with a technology focus across all areas of the business.3.Further high-grade portfolio with monetization of several billion dollars of assets.4.Reduce debt balances.5.Return cash to shareholders.30Oil, Gas and NGL Production31(1)Prices presented exclude any effects of oil, gas and NGL derivatives.The volume and price changes in the tables above caused the following changes to our commodity sales between the three and nine months ended September 30, – Q1 2018 vs. Q4 2017 and 2016.Commodity sales increased in the third quarter and the first nine months of 2017 due to price increases for all commodities. The increase in oil and bitumen sales resulted from a higher average WTI crude oil index price. Additionally, our bitumen sales benefited from tighter heavy oil differentials. The increases in gas and NGL sales were due to higher North American regional index prices upon which our gas sales are based and higher NGL prices at the Mont Belvieu, Texas hub. increases in sales duefollowing graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. Due to the favorable movement in commodity prices was partially offset by a decline in production volumes. In 2016, we significantly reduced our drilling and completion capital programs in response to depressed commodity prices. Consequently, production from our retained U.S. assets, other than STACK, steadily declined throughout 2016 and into 2017. Our 2016 asset divestiture program also caused our volumes to decline significantly in the third and fourth quarters of 2016. Additionally, Hurricane Harvey negatively impacted our third quarter 2017 production in the Eagle Ford as we temporarily suspended operations.32A summarynature of our openbusiness, including an inherently volatile commodity derivative positions is includedprice environment, we have provided a sequential quarter analysis in Note 3order to facilitate the review of our operational results and provide further transparency of our business. Specifically, the graph below shows the change in net earnings from the three months ended December 31, 2017 to the financial statements includedthree months ended March 31, 2018. The material changes are further discussed by category on the following pages. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Additional information regarding noncontrolling interests is discussed in Note 20 in “Part I. Financial Information – Item 1. Financial Statements” of this report.following tables provide financial information associated with our oil, gas and NGL hedges. The first tablegraph below presents the cash settlements and fair value gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effectsdrivers of the cash settlements. The prices do not includeupstream operations change presented above, with additional details and discussion of the effects of fair value gains and losses.3331various commodity derivatives. the instruments described in Note 4 in “Part I. Financial Information – Item 1. Financial Statements” in this report. relationshipsrelationship between contract prices and the associated forward curves. Including the cash settlements discussed above, our oil, gas and NGL derivatives incurred a net loss in the third quarter of 2017 and generated a net gain in the third quarter of 2016. Including the cash settlements discussed above, our oil, gas and NGL derivatives generated a net gain during the first nine months of 2017 and incurred a net loss during the first nine months of 2016.Marketing and Midstream Revenues and Operating ExpensesThe overall increaseAs discussed in marketing and midstream operating margin during the third quarter and the first nine months of 2017 was primarily due to an increase in EnLink’s throughput volumes related to gas processing and transmission activities, offset by a decline in margins on Devon’s downstream marketing commitments. Devon is actively engaged in optimization activities to improve margins to help offset the costs of downstream commitments; however, we expect those commitments to negatively impact our margins throughout 2017.Asset Dispositions and Other In conjunction with the non-core upstream asset divestitures, we recognized a gain during the third quarter of 2016. For further discussion, see Note 2in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.Lease Operating ExpensesTotal LOEreport, gathering, processing and LOE per Boetransportation expense increased during the third quarter of 2017$65 million primarily due to higher transportationthe presentation of $38 million resultingcertain processing arrangements changing from tolls on Canada’s Access Pipeline of $27 million, which commenceda net to a gross presentation. The change resulted in the fourth quarter of 2016 subsequent to the sale of our interest in the pipeline, and continued development of the STACK.Total LOE decreased during the first nine months of 2017 primarily dueincreases to our non-core U.S. property divestitures during 2016upstream revenues and continued well optimization and cost reduction initiatives across our portfolio which have offset industry inflation. These initiatives have been primarily focused on reducing costs associated with water disposal, power and fuel, compression and workovers. These cost savings and non-core divestitures impact were partially offsetproduction expense by Access Pipeline transportation tolls of $87$62 million during the first nine months of 2017, which was the primary driver of the increase in total LOE per Boe.34General and Administrative ExpensesGross G&A increased during the third quarter of 2017 due2018, with no impact to an increase in costs related to automation and process improvement initiatives and decreased the first nine months of 2017 largely due to lower Devon employee costs resulting from our 2016 workforce reduction and other cost reduction initiatives. During the first nine months of 2017, reimbursed G&A decreased primarily due to the divestitures of operated properties in 2016. EnLink net G&A increased during the third quarter and for the first nine months of 2017 primarily due to higher employee compensation costs.Production and Property Taxes during each period in 2017 on an absolute dollar basis primarily due to anthe increase in our U.S. upstream revenues, on which the majority of our production taxes are assessed.During the first nine months of 2017, property and other taxes decreased primarily as a result of lower property value assessments from the local taxing authorities across our key operating areas and as a result of our non-core oil and gas property divestitures during 2016. Property taxes do not always change in direct correlation with the change in oil, gas and NGL sales and are generally determined based on the valuation of the underlying assets.Depreciation, Depletion and Amortization35DD&A from our oil and gas properties decreasedAs further discussed in the third quarter primarily due to lower production and decreased during the first nine months of 2017 largely due to lower DD&A rates, resulting from the oil and gas asset impairments and non-core U.S. divestures in 2016. DD&A from our other assets decreased due to the divestiture of Access Pipeline in the fourth quarter of 2016.EnLink’s DD&A increased primarily due to acquisitions made during 2016 and gathering system expansions in 2017.Asset ImpairmentsDuring the third quarter and the first nine months of 2016, we recognized asset impairments totaling $319 million and $4.9 billion, respectively. For further discussion, see Note 52 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.Restructuringreport, in 2018 EnLink’s marketing and Transaction CostsDuring the first nine months of 2016, we recognized restructuring costs of $249midstream revenues decreased by $138 million with a corresponding decrease to marketing and midstream expenses as a result of complying with the new revenue recognition accounting standard.reductionportion of acreage in workforce driven by our cost reduction initiativesU.S. non-core operations upon which we do not intend to pursue further exploration and divestituredevelopment.non-core properties.ContentsDuring the first nine months of 2016, we recognized transactionof $17net increased $305 million primarily as a result of costs associated with the closingour $800 million early debt retirement in 2018. We estimate that total cash interest expense will be reduced by approximately $64 million on an annualized basis as a result of the acquisitions discussed in early retirement. For additional information on our debt and related expenses, see Note 216 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.Devon’s net financing costs decreased during the third quarter and the first nine months of 2017 primarily due to the 2016 repayment of $2.5 billion in borrowings, including scheduled maturities and early retirements funded with asset divestiture proceeds.EnLink’s interest on debt outstanding increased during the third quarter and the first nine months of 2017 due to increased borrowings. In the first nine months of 2017, EnLink recognized a gain on extinguishment of debt as disclosed in Note 14 in “Part I. Financial Information – Item 1. Financial Statements” of this report.Capital Resources, Uses and LiquiditySources and Uses of CashThe following table presents the major changes in cash and cash equivalents for the nine months ended September 30, 2017 and 2016.Operating Cash FlowNet cash provided by operating activities increased 96% primarily due to significantly higher commodity prices as compared to the first nine months of 2016.Our consolidated operating cash flow funded 100% of our capital expenditures during the first nine months of 2017. In 2016, leveraging our liquidity, we also used cash balancesDepreciation, Depletion and proceeds from our common stock offering and non-core asset divestitures to fund our acquisitions and capital expenditures.AmortizationDivestitures of Property and EquipmentOperating Cash FlowDuring the first nine months of 2017,Net cash provided by operating activities increased 7% primarily due to higher commodity prices as part of our announced divestiture program, we sold non-core U.S. assets for approximately $320 million, net of customary purchase price adjustments. During the first nine months of 2016, we divested certain non-core upstream assets in the U.S. for approximately $1.9 billion. For further discussion, see Note 2 in “Part 1. Financial Information – Item 1. Financial Statements” in this report.Issuance of Common StockIn February 2016, we issued 79 million shares of our common stockcompared to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.Proceeds from Sale of InvestmentDuring the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million. Proceeds were primarily used to pay a portion2017.the $250 million installment payment related to EnLink’s 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.37Capital Expenditures and Acquisitions of Property, Equipment and BusinessesThe amounts in the table below reflect cash payments forour capital expenditures including cash paid for capital expenditures incurred in prior periods.Capital expenditures consist of amounts related to our oil and gas exploration and development operations, midstream operations, other corporate activities and EnLink growth and maintenance activities. The vast majority of Devon’s capital expenditures are for the acquisition, drilling and development of oil and gas properties. Devon’s 2017 objectives are to concentrate capital spend in the STACK and Delaware Basin, while investing within cash flow and maintaining significant flexibility. Our capital investment program is driven by a disciplined allocation process focused on returns.Capital expenditures for midstream operations are primarily for the construction and expansion of oil and gas gathering facilities and pipelines. Midstream capital expenditures are largely impacted by oil and gas development activities.Acquisition capital for the first nine months of 2016 primarily consisted of Devon’s acquisition of assets in the STACK play for approximately $1.5 billion and EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets for $1.4 billion. Approximately $850 million and $800 million, respectively, was paid in cash at the closings with the remainder funded with equity consideration and debt. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.Debt Activity, NetDuring the first nine months of 2017, consolidated net debt borrowings increased $252 million. In May 2017, EnLink issued $500 million of 5.45% senior notes due in 2047 to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. In June 2017, EnLink redeemed its 7.125% senior unsecured notes due in 2022 for aggregate cash consideration of $174 million. Additionally, EnLink reduced its credit facility borrowings $74 million during the first nine months of 2017.During the first nine months of 2016, our consolidated net debt borrowings decreased $1.8 billion. The decrease was primarily due to completed tender offers to purchase and redeem $1.2 billion of debt securities. For additional information, see Note 14 in “Part I. Financial Information – Item 1. Financial Statements” in this report. The remaining decrease was due to reducing our commercial paper balances by $626 million during the first nine months of 2016.Payment of Installment Payable During the first quarter of 2017, EnLink made the first installment payment related to its 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.2018.38Shareholder and Noncontrolling Interests DistributionsThe following table summarizes our common stock dividends during the first nine months of 2017 and 2016. In the second quarter of 2016, we decreased our quarterly cash dividend rate to $0.06 per share.EnLink and the General Partner distributed $247 million and $224 million to non-Devon unitholders during the first nine months of 2017 and 2016, respectively.EnLink and General Partner DistributionsDevon received $199 million in distributions from EnLink and the General Partner during the first nine months of 2017 and 2016.Issuance of Subsidiary UnitsDuring the first nine months of 2017, EnLink issued and sold 5 million common units through its “at the market” programs and generated $92 million in net proceeds. In September 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.In January 2016, as part of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as consideration in the transaction. Additionally, during the first nine months of 2016, EnLink issued and sold 7 million common units for net proceeds of $110 million through its “at the market” programs.LiquidityOur primary sources of capital and liquidity are our operating cash flow, asset divestiture proceeds and cash on hand. Additionally, we maintain a commercial paper program, supported by our revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. Available sources of capital and liquidity also include, among other things, debt and equity securities that can be issued pursuant to our shelf registration statement filed with the SEC, as well as the sale of a portion of our common units representing interests in our investment in EnLink and the General Partner. We estimate the combination of these sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments and other contractual commitments as discussed in this section.consolidated operating cash flow increased approximately $1.2 billion$58 million in the first ninethree months of 20172018 compared to the first ninethree months of 20162017 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjust our capital program to invest within our operating cash flow. Furthermore, proceeds from non-core asset divestitures will provide additional liquidity as needed.39September 30, 2017,March 31, 2018, see Note 34 in “Part I. Financial Information – Item 1. Financial Statements” in this report.May 2017,March 2018, we announcedadvanced this divestiture goal by announcing the sale of our Johnson Country asset in the southern part of the Barnett Shale position for $553 million, subject to customary purchase price adjustments. This transaction is expected to close during the second quarter of 2018.programseparate transaction within the Barnett, we formed a partnership in April 2018 under which we will monetize half our working interest across 116 gross undrilled locations for an approximate $75 million payment spread over the next five years. With this agreement, we will also drill and operate up to divest24 wells per year, with volumes dedicated to the EnLink gathering and processing infrastructure.upstream assets. These non-core assets identified for monetization include select portions ofacross our U.S. portfolio as we progress toward the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. The most significant asset remaining in this program is select Barnett Shale leasehold. Data rooms for the Barnett properties opened in September 2017 and initial bids are expected during the fourth quarter of 2017.$5 billion target.Excluding EnLink,The following table below presents our 2017expected 2018 capital expenditures are expected to range from $2.4 billion to $2.5 billion, including $2.0 billion to $2.1 billion for our exploration and development capital program. Our capital expenditures excluding EnLink were $1.7 billion in the first nine months of 2017 and are forecasted to range from $0.7 billion to $0.8 billion in the fourth quarter of 2017.expenditures.September 30, 2017,March 31, 2018, we had approximately $2.9 billion available under this facility, net of $59$51 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At September 30, 2017,March 31, 2018, there were no borrowings under our commercial paper program.EnLink LiquidityEnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million secured revolving credit facility. As of September 30, 2017, there were $9 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility and $74 million in outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.In January 2017, EnLink paid the first $250 million installment payment related to the 2016 Anadarko Basin gathering and processing midstream assets acquisition. The remaining $250 million installment payment is payable by January 2018.In March 2017,Our credit rating from Fitch Ratings affirmed ouris BBB+ with a stable outlook. Our credit rating and revised our outlook to stable from negative. In April 2017, Moody’s Investor Service upgraded our credit rating from Ba2 tois Ba1 with a stable outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted under certain contractual arrangements.During March 2018, our Board of Directors authorized a $1.0 billion share-repurchase program of our common stock, which expires March 7, 2019. Through March 31, 2018, we repurchased 2.6 million common shares for $83 million, or $32.19 per share, with up to approximately $917 million expected to be repurchased under the share-repurchase program through the end of 2018.40EnLink LiquidityTableEnLink has a $1.5 billion unsecured revolving credit facility. The General Partner has a $250 million secured revolving credit facility. As of ContentsMarch 31, 2018, there were $10 million in outstanding letters of credit and $370 million in outstanding borrowings under the $1.5 billion credit facility and $77 million in outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.The amountAs discussed in our 2017 Annual Report on Form 10-K, in December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of income taxes recorded requires interpretationsthe Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year after the enactment date. As the Tax Reform Legislation was passed late in the fourth quarter of complex rules2017 and regulationsongoing guidance and accounting interpretation are expected over the next 12 months, we consider the accounting of federal, state, provincial and foreignthe transition tax, jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating lossesremeasurements, and other items to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax carryforwards.positions. We routinely assessexpect to complete our deferred tax assetsanalysis within the measurement period in accordance with SAB 118.reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or allunexpected effects of the deferred tax assets will not be realized. At September 30, 2017, we continued to haveTax Reform Legislation, Devon expects a 100% valuation allowance against the U.S. deferred tax assets that largely resulted from prior year cumulative financial lossespositive impact on its future after-tax earnings, primarily due to full cost impairments. Further, we continue to record a partial valuation allowance against certain Canadian deferredthe lower federal statutory tax assets.The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of other pending matters.rate.20172018 Results” in this Item 2. that are not required by or presented in accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss) attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other 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. Amounts excluded for the third quarter and first nine months of 2017 relate to changes in asset dispositions, noncash asset impairments (including noncash unproved asset impairments and dry hole costs relating to exploration expenses), deferred tax asset valuation allowance, derivatives and financial instrument fair valuesvalue changes and foreign currency, gains and losses on asset sales, noncash asset impairments, gainscosts associated with early retirement of debt and deferred tax asset valuation allowance. Amounts excluded for the third quarter and first nine months of 2016 relate to changes in derivatives and financial instrument fair values and foreign currency, noncash asset impairments (including an impairment of goodwill), restructuring and transaction costs, gains on asset sales, costs associated with the early retirement of debt and deferred tax asset valuation allowance. .(loss) and core earnings (loss) per share attributable to Devon to their comparable GAAP measures.measures for the three months ended March 31, 2018 and 2017.September 30, 2017,March 31, 2018, we have commodity derivatives that pertain to a portion of our production for the last threenine months of 2017,2018, as well as 20182019 and 2019.2020. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 34 in “Part I. Financial Information – Item 1. Financial Statements” in this report.September 30, 2017,March 31, 2018, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $170$375 million.September 30, 2017,March 31, 2018, we had total debt of $10.4$10 billion. Of this amount, $10.3$9.6 billion bears fixed interest rates averaging 5.3%5.1%, and $74$447 million is comprised of floating rate debt with interest rates averaging 3.2%3.3%.September 30, 2017,March 31, 2018, we had open interest rate swap positions that are presented in Note 34 in “Part I. Financial Information – Item 1. Financial Statements” 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% change in these forward curves would not have materially impacted our balance sheet at September 30, 2017.March 31, 2018.September 30, 2017March 31, 2018 balance sheet.September 30, 2017March 31, 2018 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.20162017 Annual Report on Form 10-K for additional information regarding certain environmental matters involving the Company.information.20162017 Annual Report on Form 10-K.10-K.thirdfirst quarter of 2017.2018 (shares in thousands).Share repurchases representOn March 7, 2018, we announced a $1.0 billion share repurchase program. This program expires March 7, 2019. As of March 31, 2018, we had repurchased 2.6 million common shares for $83 million, or $32.19 per share, under this program. Future purchases under the program will be made in open market or private transactions, depending on market conditions, and may be discontinued at any time.10,40014,300 shares of our common stock in the thirdfirst quarter of 2017,2018, 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 Devon Plan through open-market purchases.thirdfirst quarter of 2017,2018, there were approximately 4,2003,200 shares purchased by Canadian employees.November 1, 2017May 2, 2018