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, 20172020
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
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol | Name of each exchange on which registered |
Common Stock, par value $0.10 per share | DVN | The New York Stock Exchange |
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 October 18, 2017, 525.521, 2020, 382.5 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
Part I. Financial Information |
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Item 1. |
| 6 | |
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| Consolidated | 6 |
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15 | |||
15 | |||
16 | |||
Note 8 – Net Earnings (Loss) Per Share From Continuing Operations | 17 | ||
17 | |||
Note 10 – Supplemental Information to Statements of Cash Flows | 18 | ||
18 | |||
19 | |||
19 | |||
20 | |||
20 | |||
20 | |||
21 | |||
24 | |||
25 | |||
Item 2. |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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Item 3. |
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Item 4. |
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Part II. Other Information |
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Item 1. |
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Item 1A. |
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Item 2. |
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Item 3. |
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Item 4. |
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Item 5. |
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Item 6. |
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2
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon”“Devon,” the “Company” and the “Company”“Registrant” 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 thisthis Quarterly Report on Form 10-Q:
“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.
“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.
“ASU” means Accounting Standards Update.
“Bbl” or “Bbls” means barrel or barrels.
“BKV” means Banpu Kalnin Ventures.
“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. On June 27, 2019, all of Devon’s Canadian operating assets and operations were divested. 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.
“Merger” means the merger of Merger Sub with and into WPX, with WPX continuing as the surviving corporation and a wholly-owned subsidiary of the Company, pursuant to the terms of the Merger Agreement.
“Merger Agreement” means that certain Agreement and Plan of Merger, dated September 26, 2020, by and among the Company, Merger Sub and WPX.
“Merger Sub” means East Merger Sub, Inc., a wholly-owned subsidiary of the Company.
“MMBoe” means million Boe.
3
“MMcf” means million cubic feet.
3
“N/M” means not meaningful.
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPEC” means Organization of the Petroleum Exporting Countries.
“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.credit, effective as of October 5, 2018.
“TSR” means total shareholder return.
“U.S.” means United States of America.
“VIE” means variable interest entity.
“WPX” means WPX Energy, Inc.
“WTI” means West Texas Intermediate.
“/Bbl” means per barrel.
“/d” means per day.
“/Bbl” means per barrel.
“/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 and phrases “expects,” “believes,” “will,” “would,” “could,” “continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,” “expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. Such forward-lookingAll statements, are based on our examinationother than statements of historical operating trends,facts, included in this report that address activities, events or developments that Devon expects, believes or anticipates will or may occur in the information used to prepare our December 31, 2016 reserve reports and other data in our possession or available from third parties.future are forward-looking statements. 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:to those, identified below.
The COVID-19 pandemic and its related repercussions have created significant volatility, uncertainty and turmoil in the volatility ofglobal economy and our industry. This turmoil has included an unprecedented supply-and-demand imbalance for 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 exploration and development activities;
risks related to our hedging activities;
counterparty credit risks;
regulatory restrictions, compliance costs and other risks relatingcommodities, resulting in a swift and material decline in commodity prices in early 2020. Our future actual results could differ materially from the forward-looking statements in this report due to governmental regulation,the COVID-19 pandemic and related impacts, including, with respectamong other things: contributing to environmental matters;
risks relating to our indebtedness;
a sustained or further deterioration in commodity prices; causing takeaway capacity constraints for production, resulting in production shut-ins and additional downward pressure on impacted regional pricing differentials; limiting our ability to successfully complete mergers, acquisitions and divestitures;
access sources of capital due to disruptions in financial markets; increasing the extent to which insurance covers any losses we may experience;
our limited control over third parties who operate somerisk of our oil and gas properties;
midstream capacity constraints and potential interruptions in production;
competition for leases, materials, people and capital;
cyberattacks targeting our systems and infrastructure; and
any of the othera downgrade from credit rating agencies; exacerbating counterparty credit risks and uncertainties discussed in this report, our 2016 Annual Report on Form 10-Kthe risk of supply chain interruptions; and ourincreasing the risk of operational disruptions due to social distancing measures and other filingschanges to business practices.
In addition to the risks associated with the SEC.COVID-19 pandemic and its related impacts, our actual future results could differ materially from our expectations due to other factors, including, among other things:
• | 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 our operations, including as a result of employee misconduct; |
• | regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; |
• | risks related to regulatory, social and market efforts to address climate change; |
• | risks related to our hedging activities; |
• | counterparty credit risks; |
• | risks relating to our indebtedness; |
• | 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 assets, materials, people and capital; |
• | risks related to investors attempting to effect change; |
• | our ability to successfully complete mergers, acquisitions and divestitures; |
• | risks related to the Merger, including restrictions on our operations during the pendency of the Merger, litigation risk, the risk that the Merger Agreement may be terminated and the risk that we may not realize the anticipated benefits of the Merger or successfully integrate the two companies; and |
• | any of the other risks and uncertainties discussed in this report, our 2019 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 COMPREHENSIVE EARNINGS
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (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 | ) |
Marketing and midstream revenues |
|
| 2,055 |
|
|
| 1,690 |
|
|
| 5,992 |
|
|
| 4,503 |
|
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 |
|
Depreciation, depletion and amortization |
|
| 400 |
|
|
| 394 |
|
|
| 1,162 |
|
|
| 1,420 |
|
Asset impairments |
|
| 2 |
|
|
| 319 |
|
|
| 9 |
|
|
| 4,851 |
|
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 |
|
Earnings (loss) before income taxes |
|
| 272 |
|
|
| 1,178 |
|
|
| 1,328 |
|
|
| (4,252 | ) |
Income tax expense (benefit) |
|
| 25 |
|
|
| 171 |
|
|
| 51 |
|
|
| (228 | ) |
Net earnings (loss) |
|
| 247 |
|
|
| 1,007 |
|
|
| 1,277 |
|
|
| (4,024 | ) |
Net earnings (loss) attributable to noncontrolling interests |
|
| 19 |
|
|
| 14 |
|
|
| 59 |
|
|
| (391 | ) |
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
| $ | 1,218 |
|
| $ | (3,633 | ) |
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
| $ | 0.43 |
|
| $ | 1.90 |
|
| $ | 2.32 |
|
| $ | (7.22 | ) |
Diluted |
| $ | 0.43 |
|
| $ | 1.89 |
|
| $ | 2.31 |
|
| $ | (7.22 | ) |
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 247 |
|
| $ | 1,007 |
|
| $ | 1,277 |
|
| $ | (4,024 | ) |
Other comprehensive earnings, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation |
|
| 1 |
|
|
| 2 |
|
|
| 1 |
|
|
| 28 |
|
Pension and postretirement plans |
|
| 5 |
|
|
| 11 |
|
|
| 14 |
|
|
| 20 |
|
Other |
|
| — |
|
|
| — |
|
|
| (2 | ) |
|
| — |
|
Other comprehensive earnings, net of tax |
|
| 6 |
|
|
| 13 |
|
|
| 13 |
|
|
| 48 |
|
Comprehensive earnings (loss) |
|
| 253 |
|
|
| 1,020 |
|
|
| 1,290 |
|
|
| (3,976 | ) |
Comprehensive earnings (loss) attributable to noncontrolling interests |
|
| 19 |
|
|
| 14 |
|
|
| 59 |
|
|
| (391 | ) |
Comprehensive earnings (loss) attributable to Devon |
| $ | 234 |
|
| $ | 1,006 |
|
| $ | 1,231 |
|
| $ | (3,585 | ) |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
| (Unaudited) |
| ||||||||||||||
Oil, gas and NGL sales |
| $ | 678 |
|
| $ | 919 |
|
| $ | 1,909 |
|
| $ | 2,774 |
|
Oil, gas and NGL derivatives |
|
| (87 | ) |
|
| 127 |
|
|
| 272 |
|
|
| (338 | ) |
Marketing and midstream revenues |
|
| 476 |
|
|
| 700 |
|
|
| 1,367 |
|
|
| 2,195 |
|
Total revenues |
|
| 1,067 |
|
|
| 1,746 |
|
|
| 3,548 |
|
|
| 4,631 |
|
Production expenses |
|
| 271 |
|
|
| 294 |
|
|
| 852 |
|
|
| 873 |
|
Exploration expenses |
|
| 39 |
|
|
| 18 |
|
|
| 163 |
|
|
| 29 |
|
Marketing and midstream expenses |
|
| 478 |
|
|
| 684 |
|
|
| 1,395 |
|
|
| 2,147 |
|
Depreciation, depletion and amortization |
|
| 299 |
|
|
| 381 |
|
|
| 999 |
|
|
| 1,115 |
|
Asset impairments |
|
| — |
|
|
| — |
|
|
| 2,666 |
|
|
| — |
|
Asset dispositions |
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| (48 | ) |
General and administrative expenses |
|
| 75 |
|
|
| 107 |
|
|
| 256 |
|
|
| 356 |
|
Financing costs, net |
|
| 66 |
|
|
| 60 |
|
|
| 200 |
|
|
| 186 |
|
Restructuring and transaction costs |
|
| 32 |
|
|
| 10 |
|
|
| 32 |
|
|
| 73 |
|
Other expenses |
|
| — |
|
|
| 3 |
|
|
| (35 | ) |
|
| (12 | ) |
Total expenses |
|
| 1,260 |
|
|
| 1,556 |
|
|
| 6,528 |
|
|
| 4,719 |
|
Earnings (loss) from continuing operations before income taxes |
|
| (193 | ) |
|
| 190 |
|
|
| (2,980 | ) |
|
| (88 | ) |
Income tax expense (benefit) |
|
| (90 | ) |
|
| 54 |
|
|
| (510 | ) |
|
| 3 |
|
Net earnings (loss) from continuing operations |
|
| (103 | ) |
|
| 136 |
|
|
| (2,470 | ) |
|
| (91 | ) |
Net earnings (loss) from discontinued operations, net of income taxes |
|
| 13 |
|
|
| (27 | ) |
|
| (103 | ) |
|
| 378 |
|
Net earnings (loss) |
|
| (90 | ) |
|
| 109 |
|
|
| (2,573 | ) |
|
| 287 |
|
Net earnings attributable to noncontrolling interests |
|
| 2 |
|
|
| — |
|
|
| 5 |
|
|
| — |
|
Net earnings (loss) attributable to Devon |
| $ | (92 | ) |
| $ | 109 |
|
| $ | (2,578 | ) |
| $ | 287 |
|
Basic net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings (loss) from continuing operations per share |
| $ | (0.29 | ) |
| $ | 0.34 |
|
| $ | (6.58 | ) |
| $ | (0.22 | ) |
Basic earnings (loss) from discontinued operations per share |
|
| 0.04 |
|
|
| (0.07 | ) |
|
| (0.27 | ) |
|
| 0.91 |
|
Basic net earnings (loss) per share |
| $ | (0.25 | ) |
| $ | 0.27 |
|
| $ | (6.85 | ) |
| $ | 0.69 |
|
Diluted net earnings (loss) per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings (loss) from continuing operations per share |
| $ | (0.29 | ) |
| $ | 0.34 |
|
| $ | (6.58 | ) |
| $ | (0.22 | ) |
Diluted earnings (loss) from discontinued operations per share |
|
| 0.04 |
|
|
| (0.07 | ) |
|
| (0.27 | ) |
|
| 0.91 |
|
Diluted net earnings (loss) per share |
| $ | (0.25 | ) |
| $ | 0.27 |
|
| $ | (6.85 | ) |
| $ | 0.69 |
|
Comprehensive earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | (90 | ) |
| $ | 109 |
|
| $ | (2,573 | ) |
| $ | 287 |
|
Other comprehensive earnings (loss), net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency translation, discontinued operations |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 78 |
|
Release of Canadian cumulative translation adjustment, discontinued operations |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,237 | ) |
Pension and postretirement plans |
|
| 1 |
|
|
| 1 |
|
|
| 3 |
|
|
| 16 |
|
Other comprehensive earnings (loss), net of tax |
|
| 1 |
|
|
| 1 |
|
|
| 3 |
|
|
| (1,143 | ) |
Comprehensive earnings (loss): |
|
| (89 | ) |
|
| 110 |
|
|
| (2,570 | ) |
|
| (856 | ) |
Comprehensive earnings attributable to noncontrolling interests |
|
| 2 |
|
|
| — |
|
|
| 5 |
|
|
| — |
|
Comprehensive earnings (loss) attributable to Devon |
| $ | (91 | ) |
| $ | 110 |
|
| $ | (2,575 | ) |
| $ | (856 | ) |
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 |
| ||||
|
| (Unaudited) |
| |||||||||||||
|
| (Millions) |
| |||||||||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | 247 |
|
| $ | 1,007 |
|
| $ | 1,277 |
|
| $ | (4,024 | ) |
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
| 400 |
|
|
| 394 |
|
|
| 1,162 |
|
|
| 1,420 |
|
Asset impairments |
|
| 2 |
|
|
| 319 |
|
|
| 9 |
|
|
| 4,851 |
|
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 |
|
Cash settlements on commodity derivatives |
|
| 24 |
|
|
| 12 |
|
|
| 43 |
|
|
| 15 |
|
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 |
|
Share-based compensation |
|
| 33 |
|
|
| 23 |
|
|
| 122 |
|
|
| 163 |
|
Other |
|
| (85 | ) |
|
| 127 |
|
|
| (134 | ) |
|
| (31 | ) |
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 |
|
Net cash from operating activities |
|
| 776 |
|
|
| 727 |
|
|
| 2,420 |
|
|
| 1,237 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (735 | ) |
|
| (421 | ) |
|
| (2,203 | ) |
|
| (1,659 | ) |
Acquisitions of property, equipment and businesses |
|
| (6 | ) |
|
| (3 | ) |
|
| (39 | ) |
|
| (1,641 | ) |
Proceeds from sale of investment |
|
| — |
|
|
| — |
|
|
| 190 |
|
|
| — |
|
Divestitures of property and equipment |
|
| 209 |
|
|
| 1,680 |
|
|
| 323 |
|
|
| 1,889 |
|
Other |
|
| (1 | ) |
|
| 34 |
|
|
| (5 | ) |
|
| 7 |
|
Net cash from investing activities |
|
| (533 | ) |
|
| 1,290 |
|
|
| (1,734 | ) |
|
| (1,404 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Borrowings of long-term debt, net of issuance costs |
|
| 413 |
|
|
| 816 |
|
|
| 2,208 |
|
|
| 1,662 |
|
Repayments of long-term debt |
|
| (571 | ) |
|
| (2,173 | ) |
|
| (1,950 | ) |
|
| (2,722 | ) |
Payment of installment payable |
|
| — |
|
|
| — |
|
|
| (250 | ) |
|
| — |
|
Net short-term debt repayments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (626 | ) |
Early retirement of debt |
|
| — |
|
|
| (82 | ) |
|
| (6 | ) |
|
| (82 | ) |
Issuance of common stock |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,469 |
|
Issuance of subsidiary units |
|
| 414 |
|
|
| 59 |
|
|
| 486 |
|
|
| 835 |
|
Dividends paid on common stock |
|
| (30 | ) |
|
| (32 | ) |
|
| (95 | ) |
|
| (190 | ) |
Contributions from noncontrolling interests |
|
| 18 |
|
|
| 146 |
|
|
| 47 |
|
|
| 152 |
|
Distributions to noncontrolling interests |
|
| (84 | ) |
|
| (77 | ) |
|
| (247 | ) |
|
| (224 | ) |
Shares exchanged for tax withholdings |
|
| (3 | ) |
|
| (2 | ) |
|
| (67 | ) |
|
| (30 | ) |
Other |
|
| — |
|
|
| (1 | ) |
|
| (2 | ) |
|
| (7 | ) |
Net cash from financing activities |
|
| 157 |
|
|
| (1,346 | ) |
|
| 124 |
|
|
| 237 |
|
Effect of exchange rate changes on cash |
|
| 12 |
|
|
| (9 | ) |
|
| 12 |
|
|
| 5 |
|
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 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
|
| (Unaudited) |
| |||||||||||||
Cash flows from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings (loss) |
| $ | (90 | ) |
| $ | 109 |
|
| $ | (2,573 | ) |
| $ | 287 |
|
Adjustments to reconcile net earnings (loss) to net cash from operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (earnings) loss from discontinued operations, net of income taxes |
|
| (13 | ) |
|
| 27 |
|
|
| 103 |
|
|
| (378 | ) |
Depreciation, depletion and amortization |
|
| 299 |
|
|
| 381 |
|
|
| 999 |
|
|
| 1,115 |
|
Asset impairments |
|
| — |
|
|
| — |
|
|
| 2,666 |
|
|
| — |
|
Leasehold impairments |
|
| 36 |
|
|
| 13 |
|
|
| 149 |
|
|
| 15 |
|
Accretion on discounted liabilities |
|
| 8 |
|
|
| 8 |
|
|
| 24 |
|
|
| 25 |
|
Total (gains) losses on commodity derivatives |
|
| 87 |
|
|
| (127 | ) |
|
| (272 | ) |
|
| 338 |
|
Cash settlements on commodity derivatives |
|
| 10 |
|
|
| 71 |
|
|
| 343 |
|
|
| 125 |
|
Gains on asset dispositions |
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| (48 | ) |
Deferred income tax expense (benefit) |
|
| — |
|
|
| 52 |
|
|
| (311 | ) |
|
| 2 |
|
Share-based compensation |
|
| 31 |
|
|
| 23 |
|
|
| 70 |
|
|
| 92 |
|
Other |
|
| 1 |
|
|
| 3 |
|
|
| 5 |
|
|
| (9 | ) |
Changes in assets and liabilities, net |
|
| 58 |
|
|
| 36 |
|
|
| (97 | ) |
|
| (100 | ) |
Net cash from operating activities - continuing operations |
|
| 427 |
|
|
| 595 |
|
|
| 1,106 |
|
|
| 1,464 |
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
| (204 | ) |
|
| (526 | ) |
|
| (936 | ) |
|
| (1,502 | ) |
Acquisitions of property and equipment |
|
| — |
|
|
| (5 | ) |
|
| (5 | ) |
|
| (28 | ) |
Divestitures of property and equipment |
|
| 1 |
|
|
| 9 |
|
|
| 29 |
|
|
| 347 |
|
Net cash from investing activities - continuing operations |
|
| (203 | ) |
|
| (522 | ) |
|
| (912 | ) |
|
| (1,183 | ) |
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayments of long-term debt |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (162 | ) |
Repurchases of common stock |
|
| — |
|
|
| (561 | ) |
|
| (38 | ) |
|
| (1,746 | ) |
Dividends paid on common stock |
|
| (43 | ) |
|
| (35 | ) |
|
| (119 | ) |
|
| (106 | ) |
Contributions from noncontrolling interests |
|
| 1 |
|
|
| — |
|
|
| 12 |
|
|
| — |
|
Distributions to noncontrolling interests |
|
| (4 | ) |
|
| — |
|
|
| (10 | ) |
|
| — |
|
Shares exchanged for tax withholdings and other |
|
| — |
|
|
| (1 | ) |
|
| (17 | ) |
|
| (23 | ) |
Net cash from financing activities - continuing operations |
|
| (46 | ) |
|
| (597 | ) |
|
| (172 | ) |
|
| (2,037 | ) |
Net change in cash, cash equivalents and restricted cash of continuing operations |
|
| 178 |
|
|
| (524 | ) |
|
| 22 |
|
|
| (1,756 | ) |
Cash flows from discontinued operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities |
|
| 45 |
|
|
| (94 | ) |
|
| (129 | ) |
|
| 37 |
|
Investing activities |
|
| 1 |
|
|
| (5 | ) |
|
| 171 |
|
|
| 2,472 |
|
Financing activities |
|
| 0 |
|
|
| (1,571 | ) |
|
| 0 |
|
|
| (1,579 | ) |
Effect of exchange rate changes on cash |
|
| 4 |
|
|
| (3 | ) |
|
| (11 | ) |
|
| 36 |
|
Net change in cash, cash equivalents and restricted cash of discontinued operations |
|
| 50 |
|
|
| (1,673 | ) |
|
| 31 |
|
|
| 966 |
|
Net change in cash, cash equivalents and restricted cash |
|
| 228 |
|
|
| (2,197 | ) |
|
| 53 |
|
|
| (790 | ) |
Cash, cash equivalents and restricted cash at beginning of period |
|
| 1,669 |
|
|
| 3,853 |
|
|
| 1,844 |
|
|
| 2,446 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 1,897 |
|
| $ | 1,656 |
|
| $ | 1,897 |
|
| $ | 1,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of cash, cash equivalents and restricted cash: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 1,707 |
|
| $ | 1,375 |
|
| $ | 1,707 |
|
| $ | 1,375 |
|
Cash restricted for discontinued operations |
|
| 190 |
|
|
| 280 |
|
|
| 190 |
|
|
| 280 |
|
Restricted cash included in other current assets |
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Total cash, cash equivalents and restricted cash |
| $ | 1,897 |
|
| $ | 1,656 |
|
| $ | 1,897 |
|
| $ | 1,656 |
|
See accompanying notes to consolidated financial statements
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Unaudited) |
|
|
|
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| |||
|
| (Millions, except share data) |
|
| (Unaudited) |
|
|
|
|
| ||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
| $ | 2,781 |
|
| $ | 1,959 |
|
| $ | 1,707 |
|
| $ | 1,464 |
|
Cash restricted for discontinued operations |
|
| 190 |
|
|
| 380 |
| ||||||||
Accounts receivable |
|
| 1,462 |
|
|
| 1,356 |
|
|
| 493 |
|
|
| 832 |
|
Assets held for sale |
|
| — |
|
|
| 193 |
| ||||||||
Current assets associated with discontinued operations |
|
| 728 |
|
|
| 896 |
| ||||||||
Other current assets |
|
| 379 |
|
|
| 264 |
|
|
| 359 |
|
|
| 279 |
|
Total current assets |
|
| 4,622 |
|
|
| 3,772 |
|
|
| 3,477 |
|
|
| 3,851 |
|
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 |
|
| 4,553 |
|
|
| 7,558 |
| ||||||||
Other property and equipment, net ($100 million and $80 million related to CDM in 2020 and 2019, respectively) |
|
| 1,003 |
|
|
| 1,035 |
| ||||||||
Total property and equipment, net |
|
| 5,556 |
|
|
| 8,593 |
| ||||||||
Goodwill |
|
| 3,964 |
|
|
| 3,964 |
|
|
| 753 |
|
|
| 753 |
|
Right-of-use assets |
|
| 226 |
|
|
| 243 |
| ||||||||
Other long-term assets |
|
| 1,891 |
|
|
| 1,987 |
|
|
| 233 |
|
|
| 196 |
|
Long-term assets associated with discontinued operations |
|
| 81 |
|
|
| 81 |
| ||||||||
Total assets |
| $ | 27,559 |
|
| $ | 25,913 |
|
| $ | 10,326 |
|
| $ | 13,717 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 797 |
|
| $ | 642 |
|
| $ | 415 |
|
| $ | 428 |
|
Revenues and royalties payable |
|
| 1,012 |
|
|
| 908 |
|
|
| 562 |
|
|
| 730 |
|
Short-term debt |
|
| 20 |
|
|
| — |
| ||||||||
Current liabilities associated with discontinued operations |
|
| 463 |
|
|
| 459 |
| ||||||||
Other current liabilities |
|
| 1,003 |
|
|
| 1,066 |
|
|
| 269 |
|
|
| 310 |
|
Total current liabilities |
|
| 2,832 |
|
|
| 2,616 |
|
|
| 1,709 |
|
|
| 1,927 |
|
Long-term debt |
|
| 10,383 |
|
|
| 10,154 |
|
|
| 4,297 |
|
|
| 4,294 |
|
Lease liabilities |
|
| 245 |
|
|
| 244 |
| ||||||||
Asset retirement obligations |
|
| 1,100 |
|
|
| 1,226 |
|
|
| 398 |
|
|
| 380 |
|
Other long-term liabilities |
|
| 645 |
|
|
| 894 |
|
|
| 372 |
|
|
| 426 |
|
Long-term liabilities associated with discontinued operations |
|
| 157 |
|
|
| 185 |
| ||||||||
Deferred income taxes |
|
| 665 |
|
|
| 648 |
|
|
| — |
|
|
| 341 |
|
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 |
| ||||||||
Stockholders' equity: |
|
|
|
|
|
|
|
| ||||||||
Common stock, $0.10 par value. Authorized 1.0 billion shares; issued 383 million and 382 million shares in 2020 and 2019, respectively |
|
| 38 |
|
|
| 38 |
| ||||||||
Additional paid-in capital |
|
| 7,207 |
|
|
| 7,237 |
|
|
| 2,750 |
|
|
| 2,735 |
|
Accumulated deficit |
|
| (428 | ) |
|
| (1,646 | ) | ||||||||
Accumulated other comprehensive earnings |
|
| 297 |
|
|
| 284 |
| ||||||||
Retained earnings |
|
| 351 |
|
|
| 3,148 |
| ||||||||
Accumulated other comprehensive loss |
|
| (116 | ) |
|
| (119 | ) | ||||||||
Total stockholders’ equity attributable to Devon |
|
| 7,129 |
|
|
| 5,927 |
|
|
| 3,023 |
|
|
| 5,802 |
|
Noncontrolling interests |
|
| 4,805 |
|
|
| 4,448 |
|
|
| 125 |
|
|
| 118 |
|
Total equity |
|
| 11,934 |
|
|
| 10,375 |
|
|
| 3,148 |
|
|
| 5,920 |
|
Total liabilities and equity |
| $ | 27,559 |
|
| $ | 25,913 |
|
| $ | 10,326 |
|
| $ | 13,717 |
|
See accompanying notes to consolidated financial statements
8
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
| ||
|
|
|
|
|
|
|
|
|
| Additional |
|
| Retained |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Additional |
|
|
|
|
|
| Comprehensive |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
|
| Common Stock |
|
| Paid-In |
|
| Earnings |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
|
| Common Stock |
|
| Paid-In |
|
| Retained |
|
| Earnings |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
| ||||||||||||||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| (Accumulated Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
|
| Shares |
|
| Amount |
|
| Capital |
|
| Earnings |
|
| (Loss) |
|
| Stock |
|
| Interests |
|
| Equity |
| ||||||||||||||||
|
| (Unaudited) |
|
| (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 |
| ||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Balance as of June 30, 2020 |
|
| 383 |
|
| $ | 38 |
|
| $ | 2,720 |
|
| $ | 586 |
|
| $ | (117 | ) |
| $ | — |
|
| $ | 126 |
|
| $ | 3,353 |
| ||||||||||||||||||||||||||||||||
Net earnings (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (92 | ) |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| (90 | ) | ||||||||||||||||||||||||||||||||
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
| ||||||||||||||||||||||||||||||||
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| (1 | ) | ||||||||||||||||||||||||||||||||
Common stock retired |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
| ||||||||||||||||||||||||||||||||
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (143 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (143 | ) | ||||||||||||||||||||||||||||||||
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 31 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 31 |
| ||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 1 |
| ||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (4 | ) |
|
| (4 | ) | ||||||||||||||||||||||||||||||||
Balance as of September 30, 2020 |
|
| 383 |
|
| $ | 38 |
|
| $ | 2,750 |
|
| $ | 351 |
|
| $ | (116 | ) |
| $ | — |
|
| $ | 125 |
|
| $ | 3,148 |
| ||||||||||||||||||||||||||||||||
Three Months Ended September 30, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Balance as of June 30, 2019 |
|
| 410 |
|
| $ | 41 |
|
| $ | 3,352 |
|
| $ | 3,738 |
|
| $ | (117 | ) |
| $ | (20 | ) |
| $ | — |
|
| $ | 6,994 |
| ||||||||||||||||||||||||||||||||
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,218 |
|
|
| — |
|
|
| — |
|
|
| 59 |
|
|
| 1,277 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 109 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 109 |
|
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
| ||||||||||||||||||||||||||||||||
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (549 | ) |
|
| — |
|
|
| (549 | ) | ||||||||||||||||||||||||||||||||
Common stock retired |
|
| (23 | ) |
|
| (2 | ) |
|
| (559 | ) |
|
| — |
|
|
| — |
|
|
| 561 |
|
|
| — |
|
|
| — |
| ||||||||||||||||||||||||||||||||
Common stock dividends |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (35 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (35 | ) | ||||||||||||||||||||||||||||||||
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 22 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 22 |
| ||||||||||||||||||||||||||||||||
Balance as of September 30, 2019 |
|
| 387 |
|
| $ | 39 |
|
| $ | 2,815 |
|
| $ | 3,812 |
|
| $ | (116 | ) |
| $ | (8 | ) |
| $ | — |
|
| $ | 6,542 |
| ||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Balance as of December 31, 2019 |
|
| 382 |
|
| $ | 38 |
|
| $ | 2,735 |
|
| $ | 3,148 |
|
| $ | (119 | ) |
| $ | — |
|
| $ | 118 |
|
| $ | 5,920 |
| ||||||||||||||||||||||||||||||||
Net earnings (loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,578 | ) |
|
| — |
|
|
| — |
|
|
| 5 |
|
|
| (2,573 | ) | ||||||||||||||||||||||||||||||||
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
Restricted stock grants, net of cancellations |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (55 | ) |
|
| — |
|
|
| (55 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| — |
|
|
| 43 |
|
|
| — |
|
|
| — |
|
|
| (3 | ) |
|
| — |
|
|
| (55 | ) |
|
| — |
|
|
| — |
|
|
| 55 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (95 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (95 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (219 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (219 | ) |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 96 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 96 |
|
|
| 1 |
|
|
| — |
|
|
| 70 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 70 |
|
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 12 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 545 |
|
|
| 557 |
| ||||||||||||||||||||||||||||||||
Contributions from noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 12 |
|
|
| 12 |
| ||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (247 | ) |
|
| (247 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (10 | ) |
|
| (10 | ) |
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 |
| ||||||||||||||||||||||||||||||||
Balance as of September 30, 2020 |
|
| 383 |
|
| $ | 38 |
|
| $ | 2,750 |
|
| $ | 351 |
|
| $ | (116 | ) |
| $ | — |
|
| $ | 125 |
|
| $ | 3,148 |
| ||||||||||||||||||||||||||||||||
Nine Months Ended September 30, 2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||||||||||||||||||
Balance as of December 31, 2018 |
|
| 450 |
|
| $ | 45 |
|
| $ | 4,486 |
|
| $ | 3,650 |
|
| $ | 1,027 |
|
| $ | (22 | ) |
| $ | — |
|
| $ | 9,186 |
| ||||||||||||||||||||||||||||||||
Effect of adoption of lease accounting |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (19 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (19 | ) | ||||||||||||||||||||||||||||||||
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 287 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 287 |
| ||||||||||||||||||||||||||||||||
Other comprehensive loss, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,143 | ) |
|
| — |
|
|
| — |
|
|
| (1,143 | ) | ||||||||||||||||||||||||||||||||
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,755 | ) |
|
| — |
|
|
| (1,755 | ) |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| — |
|
|
| (66 | ) |
|
| (6 | ) |
|
| (1,763 | ) |
|
| — |
|
|
| — |
|
|
| 1,769 |
|
|
| — |
|
|
| — |
|
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (65 | ) |
|
| (125 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (190 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (106 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (106 | ) |
Common stock issued |
|
| 103 |
|
|
| 10 |
|
|
| 2,117 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,127 |
| ||||||||||||||||||||||||||||||||
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 142 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 142 |
|
|
| — |
|
|
| — |
|
|
| 92 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 92 |
|
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 |
| ||||||||||||||||||||||||||||||||
Balance as of September 30, 2019 |
|
| 387 |
|
| $ | 39 |
|
| $ | 2,815 |
|
| $ | 3,812 |
|
| $ | (116 | ) |
| $ | (8 | ) |
| $ | — |
|
| $ | 6,542 |
|
See accompanying notes to consolidated financial statements
9
9
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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 20162019 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, 20172020 and 20162019 and Devon’s financial position as of September 30, 2017.
Recently Adopted Accounting Standards
In January 2017, Devon adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718)2020. As further discussed in Note 17, ImprovementsDevon closed on the sale of its Barnett Shale assets on October 1, 2020, and sold its Canadian operations in the second quarter of 2019. Activity relating to Employee Share-Based Payment Accounting. Its objective is to simplify several aspectsDevon’s Barnett Shale assets, inclusive of properties divested as partial sales of the accounting for share-based payments, including income taxes when awards vest orBarnett Shale common operating field in previous reporting periods located primarily in Johnson and Wise counties, Texas, and its Canadian operations are settled, statutory withholding and forfeitures. As the result of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefits and deficiencies in theclassified as discontinued operations within Devon’s consolidated comprehensive statements of comprehensive earnings and as operating cash flows in the consolidated statements of cash flows. Devon also retrospectively applied the new cash flow statement guidance dictating the presentationThe associated assets and liabilities of shares exchanged for tax-withholding purposesDevon’s Barnett Shale assets and Canadian operations are presented as a financing activity. The adoption of the new guidance 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 goodwillassets and liabilities associated 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 impactdiscontinued operations on the consolidated financial statements.balance sheets.
During the fourth quarter of 2019, Devon will perform future goodwill impairment tests accordingentered into an agreement to ASU 2017-04.form Cotton Draw Midstream, L.L.C. (“CDM”), a joint-venture entity in the Delaware Basin with an affiliate of QL Capital Partners, LP (“QLCP”). Devon holds a controlling interest in CDM and the portions of CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as noncontrolling interests in the accompanying consolidated statements of comprehensive earnings and consolidated balance sheets. CDM is considered a VIE to Devon. The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which the creditors do not have recourse to Devon's assets are also included in, and disclosed parenthetically, on Devon's consolidated balance sheets if material.
Issued Accounting Standards Not Yet Adopted
Disaggregation of Revenue
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 offollowing table presents revenue from contracts with customers. Its objective is to increasecustomers that are disaggregated based on the usefulnesstype 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 resultsgood 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.service.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Oil |
| $ | 504 |
|
| $ | 751 |
|
| $ | 1,462 |
|
| $ | 2,160 |
|
Gas |
|
| 79 |
|
|
| 80 |
|
|
| 221 |
|
|
| 291 |
|
NGL |
|
| 95 |
|
|
| 88 |
|
|
| 226 |
|
|
| 323 |
|
Oil, gas and NGL sales |
|
| 678 |
|
|
| 919 |
|
|
| 1,909 |
|
|
| 2,774 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
| 233 |
|
|
| 407 |
|
|
| 702 |
|
|
| 1,157 |
|
Gas |
|
| 97 |
|
|
| 140 |
|
|
| 268 |
|
|
| 530 |
|
NGL |
|
| 143 |
|
|
| 151 |
|
|
| 390 |
|
|
| 506 |
|
Total marketing revenues |
|
| 473 |
|
|
| 698 |
|
|
| 1,360 |
|
|
| 2,193 |
|
Midstream revenues |
|
| 3 |
|
|
| 2 |
|
|
| 7 |
|
|
| 2 |
|
Marketing and midstream revenues |
|
| 476 |
|
|
| 700 |
|
|
| 1,367 |
|
|
| 2,195 |
|
Total revenues from contracts with customers |
| $ | 1,154 |
|
| $ | 1,619 |
|
| $ | 3,276 |
|
| $ | 4,969 |
|
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
TheRecently Adopted Accounting Standards
In 2016, the FASB issued ASU 2016-02, Leases (Topic 842).2016-13, Financial Instruments-Credit Losses. This ASU will supersedechanges the lease requirementsimpairment model for trade receivables, held-to-maturity debt securities, net investments in Topic 840, Leases. Its objectiveleases, loans and other financial assets measured at amortized cost from the current “incurred loss” model to a new forward-looking “expected loss” model. Devon adopted this ASU in the first quarter of 2020 using the modified retrospective approach. Devon assesses credit risk by class of account type which includes cash equivalents and oil and gas, marketing and midstream, joint interest and other accounts receivable. These classes are then further evaluated using a probability weighted scenario assessment based on historical losses and a probability of future default. This evaluation is supported by an assessment of risk factors such as the age of receivable, current macro-economic conditions, credit rating of the counterparty and our historical loss rate. This adoption did not have a material impact on Devon’s consolidated financial statements.
2.Acquisitions and Divestitures
Divestitures
Discontinued Operations – Upstream Assets
On October 1, 2020, Devon completed the sale of its Barnett Shale assets to increase transparency and comparability among organizations. This ASUBKV for proceeds, net of purchase price adjustments, of $490 million, including a $170 million deposit previously received in April 2020. The agreement with BKV also provides guidance requiring lesseesfor contingent earnout payments to recognize most leasesDevon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commences 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, 20192021 and will be applied usinghas a modified retrospective transition method, which requires applying the new guidanceterm of four years. Devon recognized a $748 million asset impairment related to leases that exist or are entered into after the beginning of the earliest period in the financial statements. Early adoption is permitted, but Devon does not plan to early adopt. Devon is in the process of evaluating contracts and gathering the necessary terms and data elements for purposes of determining the impact this ASU will have on its consolidated financial statements and related disclosures. Recently, the FASB issued Proposed Accounting Standards Update (ASU) No. 2017-290, 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 contracts represent a relatively small percentage of the aggregate value of contracts being evaluated but represent a significant number of contracts.
Based on continuing research, Devon estimates a large number of contracts and data elements must be gathered and reviewed to ensure proper accounting of these contracts once this ASU is effective. Devon anticipates the adoption of this standard will significantly impact its consolidated financial statements, systems, processes and controls and is evaluating technology requirements and solutions needed to comply with the requirements of this ASU.
The FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This ASU will require 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 eligible for capitalization. This ASU is effective for Devon beginning January 1, 2018, and presentation changes in the statement of earnings will be applied retrospectively, while service cost component capitalization will be applied prospectively. Upon adoption of this ASU, Devon will reclassify $7 million, $14 million and $16 million of non-service cost components of net periodic benefit costs for 2017, 2016 and 2015, respectively, as other nonoperating items. Such amounts are currently classified in Devon’s G&A. No other changes upon adopting this ASU are expected to be material.
|
|
Devon Acquisitions
In January 2016, Devon acquired approximately 80,000 net acres (unaudited) and assets in the STACK playfourth quarter of 2019 and incremental asset impairments of $179 million and $3 million during the first quarter and third quarter of 2020, respectively. Additional information can be found in Note 17.
In June 2019, Devon completed the sale of substantially all of its oil and gas assets and operations in Canada to Canadian Natural Resources Limited for approximately $1.5 billion. Devon funded the acquisition with $849 millionproceeds, net of cash, after adjustments, and $659 million of common equity shares. The purchase price allocation was approximately $1.3adjustments, of $2.6 billion ($3.4 billion Canadian dollars), and recognized a pre-tax gain of $223 million ($425 million, net of tax, primarily due to unproved properties and approximately $200 million to proved properties.a significant deferred tax benefit) in 2019. Additional information can be found in Note 17.
2017Continuing Operations – Upstream Assets
During the first quarter of 2020, Devon Asset Divestituresentered into a farmout agreement in which the third party to the agreement can participate in the development of certain Devon-owned non-operated interests in the Delaware Basin. Under the agreement, Devon will periodically transfer working interests to the third party, who will then fund its share of operating and development costs. Once certain investment hurdles are met, a portion of the working interest held by the third party will revert back to Devon. No material activity occurred during the first nine months of 2020.
In May 2017,the first quarter of 2019, Devon announcedreceived proceeds of approximately $300 million and recognized a program to divest approximately $1 billion$45 million net gain on asset dispositions, primarily from sales of upstream assets. The non-core assets identified for monetization include select portions ofin 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. EstimatedPermian Basin. In aggregate, the total estimated proved reserves associated 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, 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%25 MMBoe.
Pending Merger
On September 26, 2020, Devon and WPX entered into the Merger Agreement, providing for an all-stock merger of total U.S. proved reserves.equals. WPX is an oil and gas exploration and production company with assets in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota. On the closing date of the Merger, each share of WPX common stock will be automatically converted into the right to receive 0.5165 of a share of Devon common stock. No fractional shares of Devon’s common stock will be issued in the Merger, and holders of shares of WPX common stock will, instead, receive cash in lieu of fractional shares of Devon common stock, if any. The Merger has been unanimously approved by Devon and WPX Boards of Directors and is still subject to the approval of both Devon and WPX shareholders. The Merger is expected to close in the first quarter of 2021 subject to shareholder and regulatory approvals and other customary closing conditions.
11
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Proceeds from the transactions were used primarily for debt repayment and to support capital investment in Devon’s core resource plays.
The divestiture transactions that closed in the third quarter of 2016 significantly altered the costs and reserves relationship of Devon’s U.S. cost center. Therefore, Devon recognized a $1.4 billion gain in the third quarter of 2016 associated with these divestitures. A summary 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 |
|
EnLink Acquisitions
In January 2016, EnLink acquired Anadarko Basin gathering and processing midstream assets, along with dedicated acreage service rights and service contracts, for approximately $1.4 billion. The purchase price allocation was $1.0 billion to intangible assets 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 million of the purchase price was to be paid within one year with the option to defer $250 million of the final payment 24 months 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 liabilities in the accompanying consolidated balance sheets. The accretion of the discount is reported within net financing costs in the accompanying consolidated comprehensive statement of earnings.
In August 2016, EnLink formed a joint venture to operate and expand its midstream assets in the Delaware Basin. The joint venture is initially owned 50.1% by EnLink and 49.9% by the joint venture partner. EnLink contributed approximately $244 million of existing non-monetary assets to the joint venture and committed an additional $262 million in capital to fund potential future development projects and potential acquisitions. The joint venture partner committed an aggregate 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 portions of the joint venture partner’s interest.
EnLink Asset Divestitures
During the first quarter of 2017, EnLink divested its ownership interest in Howard Energy Partners for approximately $190 million.
|
|
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 enterenters into derivative financial instruments with respect to a portion of theirits 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.volatility. As of September 30, 2017,2020, Devon did not have any open foreign exchangeinterest rate swap 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. As of September 30, 2020, Devon neither held cash collateral of its counterparties 0r posted cash collateral to its counterparties.
Commodity Derivatives
As of September 30, 2017,2020, 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.table.
|
| 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) |
| |||||
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 |
|
Q1-Q4 2019 |
|
| 1,356 |
|
| $ | 49.79 |
|
|
| 2,096 |
|
| $ | 44.10 |
|
| $ | 54.10 |
|
|
| 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) |
| |||||
Q4 2020 |
|
| 88,000 |
|
| $ | 36.28 |
|
|
| 39,500 |
|
| $ | 50.93 |
|
| $ | 60.93 |
|
Q1-Q4 2021 |
|
| 23,810 |
|
| $ | 35.79 |
|
|
| 19,367 |
|
| $ | 40.66 |
|
| $ | 50.66 |
|
Q1 2022 |
|
| 500 |
|
| $ | 45.00 |
|
|
| 6,750 |
|
| $ | 37.93 |
|
| $ | 47.93 |
|
|
| 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 |
| |||||||
Period |
| Index |
| Volume (Bbls/d) |
|
| Weighted Average Differential to WTI ($/Bbl) |
| ||
Q4 2020 |
| Argus MEH |
|
| 50,000 |
|
| $ | 0.47 |
|
Q4 2020 |
| Midland Sweet |
|
| 32,000 |
|
| $ | (1.23 | ) |
Q4 2020 |
| NYMEX Roll |
|
| 54,000 |
|
| $ | 0.38 |
|
Q1-Q4 2021 |
| Midland Sweet |
|
| 7,000 |
|
| $ | 1.27 |
|
|
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
As of September 30, 2017,2020, 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 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 |
|
|
| 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 2020 |
|
| 69,000 |
|
| $ | 2.69 |
|
|
| 141,000 |
|
| $ | 2.35 |
|
| $ | 2.85 |
|
Q1-Q4 2021 |
|
| 32,699 |
|
| $ | 2.76 |
|
|
| 142,055 |
|
| $ | 2.38 |
|
| $ | 2.88 |
|
Q1 2022 |
|
| 14,000 |
|
| $ | 2.85 |
|
|
| 36,000 |
|
| $ | 2.60 |
|
| $ | 3.10 |
|
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 | ) |
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume (MMBtu/d) |
|
| Weighted Average Differential to Henry Hub ($/MMBtu) |
| ||
Q4 2020 |
| Panhandle Eastern Pipe Line |
|
| 30,000 |
|
| $ | (0.47 | ) |
Q4 2020 |
| El Paso Natural Gas |
|
| 65,000 |
|
| $ | (0.78 | ) |
Q4 2020 |
| Houston Ship Channel |
|
| 30,000 |
|
| $ | (0.02 | ) |
Q1-Q4 2021 |
| El Paso Natural Gas |
|
| 35,000 |
|
| $ | (0.92 | ) |
As of September 30, 2017,2020, 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 |
| ||||||||||
Q4 2020 |
| Natural Gasoline |
|
| 1,000 |
|
| $ | 44.84 |
| ||||||||||||||||||||||
Q4 2020 |
| Normal Butane |
|
| 1,500 |
|
| $ | 23.56 |
| ||||||||||||||||||||||
Q4 2020 |
| Propane |
|
| 4,500 |
|
| $ | 25.18 |
|
As of September 30, 2017, 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.
|
|
|
|
| |||||||
|
|
|
|
|
| ||||||
|
|
|
|
|
|
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 |
|
|
14
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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 | ) |
The following table presents the derivative fair values by derivative financial instrument type followed by the corresponding individual consolidated balance sheetsheets caption.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Millions) |
|
| September 30, 2020 |
|
| December 31, 2019 |
| |||||||
Commodity derivative assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current assets |
| $ | 39 |
|
| $ | 9 |
|
| $ | 27 |
|
| $ | 49 |
|
Other long-term assets |
|
| 4 |
|
|
| 1 |
|
|
| 1 |
|
|
| 1 |
|
Interest rate derivative assets: |
|
|
|
|
|
|
|
| ||||||||
Other current assets |
|
| 1 |
|
|
| 1 |
| ||||||||
Total derivative assets |
| $ | 44 |
|
| $ | 11 |
|
| $ | 28 |
|
| $ | 50 |
|
Commodity derivative liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | 53 |
|
| $ | 187 |
|
| $ | 70 |
|
| $ | 30 |
|
Other long-term liabilities |
|
| 7 |
|
|
| 16 |
|
|
| 10 |
|
|
| 1 |
|
Interest rate derivative liabilities: |
|
|
|
|
|
|
|
| ||||||||
Other current liabilities |
|
| 1 |
|
|
| — |
| ||||||||
Other long-term liabilities |
|
| 61 |
|
|
| 41 |
| ||||||||
Total derivative liabilities |
| $ | 122 |
|
| $ | 244 |
|
| $ | 80 |
|
| $ | 31 |
|
1513
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 the4.Share-Based 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 comprehensive 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 awards6 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings.comprehensive 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 |
|
|
| Nine Months Ended September 30, |
| |||||
|
| 2020 |
|
| 2019 |
| ||
G&A |
| $ | 58 |
|
| $ | 64 |
|
Exploration expenses |
|
| 1 |
|
|
| 1 |
|
Restructuring and transaction costs |
|
| 11 |
|
|
| 27 |
|
Total |
| $ | 70 |
|
| $ | 92 |
|
Related income tax benefit |
| $ | — |
|
| $ | 13 |
|
Under its approved long-term incentive plan, Devon granted share-based awards to certain employees in the first nine months of 2017.2020. 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 |
|
|
|
|
| Performance-Based |
|
| Performance |
| ||||||||||||||||||||||||||||||||||||
|
| Awards and Units |
|
| Restricted Stock Awards |
|
| Share Units |
|
| Restricted Stock Awards |
|
| 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 |
|
| 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 12/31/19 |
|
| 4,984 |
|
| $ | 29.65 |
|
|
| 153 |
|
| $ | 33.88 |
|
|
| 2,155 |
|
|
| $ | 40.35 |
| |||||||||||||||||||||||||||||
Granted |
|
| 2,691 |
|
| $ | 44.87 |
|
|
| 223 |
|
| $ | 44.85 |
|
|
| 1,010 |
|
|
| $ | 52.58 |
|
|
| 3,056 |
|
| $ | 21.90 |
|
|
| — |
|
| $ | — |
|
|
| 688 |
|
|
| $ | 27.89 |
| ||||
Vested |
|
| (2,321 | ) |
| $ | 39.51 |
|
|
| (233 | ) |
| $ | 41.27 |
|
|
| (832 | ) |
|
| $ | 78.19 |
|
|
| (2,093 | ) |
| $ | 29.11 |
|
|
| (109 | ) |
| $ | 29.51 |
|
|
| (455 | ) |
|
| $ | 52.56 |
| ||||
Forfeited |
|
| (252 | ) |
| $ | 36.06 |
|
|
| — |
|
| $ | — |
|
|
| (24 | ) |
|
| $ | 40.70 |
|
|
| (294 | ) |
| $ | 24.44 |
|
|
| — |
|
| $ | — |
|
|
| (385 | ) |
|
| $ | 47.68 |
| ||||
Unvested at 9/30/17 |
|
| 6,525 |
|
| $ | 36.83 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
| (1 | ) |
| $ | 41.21 |
| |||||||||||||||||||||||||||
Unvested at 9/30/20 |
|
| 5,653 |
|
| $ | 25.93 |
|
|
| 44 |
|
| $ | 44.70 |
|
|
| 2,003 |
|
| (1 | ) |
| $ | 31.89 |
|
(1) | A maximum of |
The following table presents the assumptions related to the performance share units granted in 2017,2020, as indicated in the previous summary table.
|
| 2017 |
|
| 2020 |
| ||||||||
Grant-date fair value |
| $ | 51.05 |
| — |
| $ | 53.12 |
|
| $ | 27.89 |
| |
Risk-free interest rate |
| 1.50% |
|
| 1.36% |
| ||||||||
Volatility factor |
| 45.8% |
|
| 38.4% |
| ||||||||
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, 2017.2020.
|
|
|
|
|
| Performance-Based |
|
|
|
|
|
|
|
|
|
| Performance-Based |
|
|
|
|
| ||
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| ||||||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
|
| Awards |
|
| Awards |
|
| Share Units |
| ||||||
Unrecognized compensation cost (millions) |
| $ | 160 |
|
| $ | 6 |
|
| $ | 35 |
| ||||||||||||
Unrecognized compensation cost |
| $ | 81 |
|
| $ | — |
|
| $ | 15 |
| ||||||||||||
Weighted average period for recognition (years) |
|
| 2.5 |
|
|
| 1.8 |
|
|
| 2.0 |
|
|
| 2.6 |
|
|
| 0.7 |
|
|
| 1.7 |
|
EnLink Share-Based Awards
In March 2017, the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees. The combined grant fair value was $10 million, and the total cost was recognized in the first quarter
14
Table of 2017 due to the awards vesting immediately.Contents
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
5.Asset Impairments
The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below are included in exploration expenses in 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 asconsolidated statements of September 30, 2017.comprehensive earnings.
|
| General Partner |
|
| EnLink |
| ||||||||||
|
| Restricted |
|
| Performance |
|
| Restricted |
|
| Performance |
| ||||
|
| Incentive Units |
|
| Units |
|
| Incentive Units |
|
| Units |
| ||||
Unrecognized compensation cost (millions) |
| $ | 14 |
|
| $ | 6 |
|
| $ | 15 |
|
| $ | 6 |
|
Weighted average period for recognition (years) |
|
| 1.8 |
|
|
| 2.0 |
|
|
| 1.7 |
|
|
| 1.9 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Proved oil and gas assets |
| $ | — |
|
| $ | — |
|
| $ | 2,664 |
|
| $ | — |
|
Other assets |
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
Total asset impairments |
| $ | — |
|
| $ | — |
|
| $ | 2,666 |
|
| $ | — |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved impairments |
| $ | 36 |
|
| $ | 13 |
|
| $ | 149 |
|
| $ | 15 |
|
|
|
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 |
|
Proved Oil and Gas and Other AssetImpairments
UnderReduced demand from the full cost methodCOVID-19 pandemic caused an unprecedented downturn in the price of accounting, capitalized costsoil. As a result, Devon reduced planned 2020 capital investment by 45%. With materially lower commodity prices and reduced near-term investment, Devon assessed all of its oil and gas properties, netfields for impairment as of accumulated DD&AMarch 31, 2020. For impairment determinations, Devon historically utilized NYMEX forward strip prices for the first five years and deferred income taxes, may not exceedapplied internally generated price forecasts for subsequent years. In response to the fullCOVID-19 pandemic, the NYMEX forward market became highly illiquid as evidenced by materially reduced trading volumes for periods beyond 2021. Therefore, Devon supplemented the NYMEX forward strip prices with price forecasts published by reputable investment banks and reservoir engineering firms to estimate future revenues as of March 31, 2020. To measure indicated impairments, Devon used a market-based weighted-average cost “ceiling” atof capital to discount 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 flowsflows. These inputs 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 declinescategorized as level 3 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 reducedfair value hierarchy.
Devon recognized approximately $2.7 billion of proved reserves values and, to a lesser degree, proved reserves.
EnLink Goodwill Impairments
Inasset impairments during the first quarter of 2020. These impairments related to the Anadarko Basin and Rockies fields in which the cost basis included acquisitions completed in 2016 EnLinkand 2015, respectively, when commodity prices were much higher than they are today. During the first quarter of 2020, Devon recognized goodwill$2 million of product line fill impairments. See Note 12 for additional details.
17
Table of ContentsUnprovedImpairments
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
6.Restructuring and Transaction Costs
The following table summarizes restructuring and transaction costs presentedDue to the downturn in the accompanying consolidated comprehensive statementcommodity price environment and reduced near-term investment as discussed above, Devon also recognized $149 million 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 |
|
Reduction in Workforce
Inunproved impairments during the first nine months of 2016,2020. Of these unproved impairments, $113 million related primarily to the Rockies field and $36 million related to certain non-core acreage Devon no longer intends to pursue for exploration opportunities. During the first nine months of 2019, Devon recognized $229$15 million in employee-related costs associated withof unproved impairments related to certain non-core acreage it no longer intended to pursue for exploration opportunities.
6.Restructuring and Transaction Costs
In August 2020, Devon announced a cost reduction in workforce.plan designed to deliver sustainable cost savings by year-end 2020. As a result, Devon recognized $32 million of restructuring expenses during the third quarter of 2020. Of these employee-related costs, approximately $60expenses, $11 million resulted from accelerated vesting of share-based grants, which are noncash charges.
During the first quarter of 2019, Devon announced workforce reductions and other initiatives designed to enhance its operational focus and cost structure in conjunction with the portfolio transformation discussed in Note 2. As a result, Devon recognized $73 million of restructuring expenses during the first nine months of 2019. Of these expenses, $27 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $30$5 million resulted from estimated settlements of defined retirement benefits.
As a result 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.
1815
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table summarizes Devon’s restructuring liabilities.
7.Income Taxes |
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, |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
Earnings (loss) from continuing operations before income taxes |
| $ | (193 | ) |
| $ | 190 |
|
| $ | (2,980 | ) |
| $ | (88 | ) | ||||||||||||||||
|
| (Millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||
Current income tax expense |
| $ | 39 |
|
| $ | 85 |
|
| $ | 71 |
|
| $ | 72 |
| ||||||||||||||||
Current income tax expense (benefit) |
| $ | (90 | ) |
| $ | 2 |
|
| $ | (199 | ) |
| $ | 1 |
| ||||||||||||||||
Deferred income tax expense (benefit) |
|
| (14 | ) |
|
| 86 |
|
|
| (20 | ) |
|
| (300 | ) |
|
| — |
|
|
| 52 |
|
|
| (311 | ) |
|
| 2 |
|
Total income tax expense (benefit) |
| $ | 25 |
|
| $ | 171 |
|
| $ | 51 |
|
| $ | (228 | ) |
| $ | (90 | ) |
| $ | 54 |
|
| $ | (510 | ) |
| $ | 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 21 | % |
|
| 21 | % |
|
| 21 | % |
|
| 21 | % |
State income taxes |
|
| 0 | % |
|
| 6 | % |
|
| 1 | % |
|
| (2 | %) | ||||||||||||||||
Change in tax legislation |
|
| 4 | % |
|
| 0 | % |
|
| 3 | % |
|
| 0 | % | ||||||||||||||||
Unrecognized tax benefits |
|
| 18 | % |
|
| 0 | % |
|
| 0 | % |
|
| (2 | %) | ||||||||||||||||
Other |
|
| 0 | % |
|
| 1 | % |
|
| (1 | %) |
|
| (20 | %) | ||||||||||||||||
Deferred tax asset valuation allowance |
|
| (9 | %) |
|
| (35 | %) |
|
| (25 | %) |
|
| (20 | %) |
|
| 4 | % |
|
| 0 | % |
|
| (7 | %) |
|
| 0 | % |
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 | % | ||||||||||||||||
Other |
|
| (19 | %) |
|
| 0 | % |
|
| (7 | %) |
|
| 3 | % | ||||||||||||||||
Effective income tax rate |
|
| 9 | % |
|
| 15 | % |
|
| 4 | % |
|
| 5 | % |
|
| 47 | % |
|
| 28 | % |
|
| 17 | % |
|
| (3 | %) |
Devon estimates its annual effective income tax rate in recordingto record 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 2016The Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) became law on March 27, 2020. The CARES Act allows net operating losses generated in taxable years beginning after December 31, 2017 and before January 1, 2021 to be carried back five years to offset taxable income and recoup previously paid taxes. As a result, Devon intends to carry back net operating losses generated in 2019 and 2020 to 2014 and 2015, respectively, and recorded a $105 million income tax benefit through the first nine months of 2017,2020.
On July 28, 2020, the Department of Treasury issued final regulations regarding the provision of the Tax Cuts and Jobs Act that limits the deduction for business interest expense. Prior to the issuance of these final regulations, Devon continuedhad reduced its CARES Act income tax benefit by $34 million due to maintainthe business interest expense limitation. With the regulatory update, Devon was able to reverse the $34 million in the third quarter of 2020 and recognize the full $105 million of benefit under the CARES Act.
Throughout 2019, Devon maintained a valuation allowance against certain deferred tax assets, including certain tax credits and state net operating losses. Since then, reduced demand from the COVID-19 pandemic has caused an unprecedented downturn in the commodity price environment. As a result, Devon recorded significant impairments during the first quarter of 2020 and is now in a net
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
deferred tax asset position. Consequently, Devon reassessed its position and recorded a 100% valuation allowance against its U.S.all net deferred tax assets resulting from prior year cumulative financial losses largely due toand has maintained a full cost impairments. Furthermore, a partial allowance continues to be held against certain Canadian segment deferred tax assets.
Devon provided an additional $796 million to 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. Devon 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.position throughout 2020.
Also in
In the table above, the “other” effect is primarily composed of permanent differences primarily related to stock compensation for which dollar amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, suchSuch items have an insignificant impact on ourDevon’s effective income tax rate. However, these items have a more noticeable impact to our rate unless pre-tax earnings or losses are relatively small in the third quarter of 2017 due to lower relative earnings during the period. During the third quarter of 2017,amount. In total, “other” is primarily related to the taxation of foreign earnings and other financing items.
In the first quarter of 2016, EnLink recorded goodwill impairments totaling $873 million. These impairments are not deductible for purposes of calculating income tax and, therefore, have an impact on the effective tax rate.
Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. The timing of resolutionrepresents $18 million of income tax examinations is uncertain as areexpense in the amounts and timingfirst nine months 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.2019.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table reconciles net earnings (loss) attributable to Devonfrom continuing operations and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.share from continuing operations.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||||||||||||||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
| $ | 1,218 |
|
| $ | (3,633 | ) | ||||||||||||||||
Net earnings (loss) from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Net earnings (loss) from continuing operations |
| $ | (105 | ) |
| $ | 136 |
|
| $ | (2,475 | ) |
| $ | (91 | ) | ||||||||||||||||
Attributable to participating securities |
|
| (2 | ) |
|
| (11 | ) |
|
| (13 | ) |
|
| (1 | ) |
|
| (2 | ) |
|
| (1 | ) |
|
| (3 | ) |
|
| (1 | ) |
Basic and diluted earnings (loss) |
| $ | 226 |
|
| $ | 982 |
|
| $ | 1,205 |
|
| $ | (3,634 | ) | ||||||||||||||||
Basic and diluted earnings (loss) from continuing operations |
| $ | (107 | ) |
| $ | 135 |
|
| $ | (2,478 | ) |
| $ | (92 | ) | ||||||||||||||||
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding - total |
|
| 526 |
|
|
| 524 |
|
|
| 525 |
|
|
| 509 |
|
|
| 383 |
|
|
| 397 |
|
|
| 383 |
|
|
| 415 |
|
Attributable to participating securities |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (5 | ) |
|
| (6 | ) |
|
| (6 | ) |
Common shares outstanding - basic |
|
| 520 |
|
|
| 518 |
|
|
| 519 |
|
|
| 503 |
|
|
| 377 |
|
|
| 392 |
|
|
| 377 |
|
|
| 409 |
|
Dilutive effect of potential common shares issuable |
|
| 3 |
|
|
| 3 |
|
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
Common shares outstanding - diluted |
|
| 523 |
|
|
| 521 |
|
|
| 522 |
|
|
| 503 |
|
|
| 377 |
|
|
| 394 |
|
|
| 377 |
|
|
| 409 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Net earnings (loss) per share from continuing operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Basic |
| $ | 0.43 |
|
| $ | 1.90 |
|
| $ | 2.32 |
|
| $ | (7.22 | ) |
| $ | (0.29 | ) |
| $ | 0.34 |
|
| $ | (6.58 | ) |
| $ | (0.22 | ) |
Diluted |
| $ | 0.43 |
|
| $ | 1.89 |
|
| $ | 2.31 |
|
| $ | (7.22 | ) |
| $ | (0.29 | ) |
| $ | 0.34 |
|
| $ | (6.58 | ) |
| $ | (0.22 | ) |
Antidilutive options (1) |
|
| 2 |
|
|
| 3 |
|
|
| 2 |
|
|
| 3 |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
(1) | Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted net earnings |
9. | Other Comprehensive Earnings (Loss) |
Components of other comprehensive earnings (loss) consist of the following:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated foreign currency translation and other |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 1,159 |
|
Change in cumulative translation adjustment |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 78 |
|
Release of Canadian cumulative translation adjustment (1) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,237 | ) |
Ending accumulated foreign currency translation and other |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (117 | ) |
|
| (117 | ) |
|
| (119 | ) |
|
| (132 | ) |
Recognition of net actuarial loss and prior service cost in earnings (2) |
|
| 1 |
|
|
| 1 |
|
|
| 4 |
|
|
| 5 |
|
Curtailment and settlement of pension benefits(3) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 15 |
|
Income tax expense |
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| (4 | ) |
Ending accumulated pension and postretirement benefits |
|
| (116 | ) |
|
| (116 | ) |
|
| (116 | ) |
|
| (116 | ) |
Accumulated other comprehensive loss, net of tax |
| $ | (116 | ) |
| $ | (116 | ) |
| $ | (116 | ) |
| $ | (116 | ) |
17
|
| 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 |
|
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| In conjunction with the sale of substantially all of its oil and gas assets and operations in Canada, Devon released the cumulative translation adjustment as part of its gain on the disposition of its Canadian business. See Note 17 for additional details. |
(2) | Recognition of net actuarial loss and prior service cost are included in the computation of net periodic benefit cost, which is a component of |
(3) | These accumulated other comprehensive earnings are included within components of other expenses and restructuring and transaction costs in the accompanying consolidated comprehensive statements of earnings. |
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 September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||||||
|
| (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 |
|
| $ | 21 |
|
| $ | 55 |
|
| $ | 339 |
|
| $ | 65 |
|
Income taxes receivable |
|
| — |
|
|
| 6 |
|
|
| 8 |
|
|
| 107 |
| ||||||||||||||||
Income tax receivable |
|
| — |
|
|
| (12 | ) |
|
| (112 | ) |
|
| (13 | ) | ||||||||||||||||
Other current assets |
|
| 12 |
|
|
| 98 |
|
|
| (43 | ) |
|
| 242 |
|
|
| 18 |
|
|
| 15 |
|
|
| 10 |
|
|
| 18 |
|
Other long-term assets |
|
| (9 | ) |
|
| 14 |
|
|
| (33 | ) |
|
| (1 | ) | ||||||||||||||||
Accounts payable |
|
| 48 |
|
|
| (34 | ) |
|
| 98 |
|
|
| (185 | ) |
|
| 11 |
|
|
| 23 |
|
|
| 9 |
|
|
| (14 | ) |
Revenues and royalties payable |
|
| 63 |
|
|
| 40 |
|
|
| 92 |
|
|
| 34 |
|
|
| 89 |
|
|
| (72 | ) |
|
| (169 | ) |
|
| (88 | ) |
Other current liabilities |
|
| 99 |
|
|
| (54 | ) |
|
| 24 |
|
|
| (77 | ) |
|
| 15 |
|
|
| 12 |
|
|
| (82 | ) |
|
| (77 | ) |
Net change in working capital |
| $ | 7 |
|
| $ | 137 |
|
| $ | 94 |
|
| $ | 208 |
| ||||||||||||||||
Interest paid (net of capitalized interest) |
| $ | 49 |
|
| $ | 113 |
|
| $ | 285 |
|
| $ | 402 |
| ||||||||||||||||
Other long-term liabilities |
|
| (87 | ) |
|
| 1 |
|
|
| (59 | ) |
|
| 10 |
| ||||||||||||||||
Total |
| $ | 58 |
|
| $ | 36 |
|
| $ | (97 | ) |
| $ | (100 | ) | ||||||||||||||||
Supplementary cash flow data - total operations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||||||||
Interest paid |
| $ | 64 |
|
| $ | 81 |
|
| $ | 194 |
|
| $ | 242 |
| ||||||||||||||||
Income taxes paid (received) |
| $ | — |
|
| $ | (7 | ) |
| $ | (1) |
|
| $ | (130 | ) |
| $ | (2 | ) |
| $ | — |
|
| $ | 170 |
|
| $ | 16 |
|
Devon’s acquisitionAs of certain STACK assets duringSeptember 30, 2020 and December 31, 2019, Devon had approximately $130 million and $250 million, respectively, of accrued capital expenditures included in “Total property and equipment, net” and “Accounts payable” on 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.
consolidated balance sheets.
11. | Accounts Receivable |
Components of accounts receivable include the following:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Millions) |
|
| September 30, 2020 |
|
| December 31, 2019 |
| |||||||
Oil, gas and NGL sales |
| $ | 528 |
|
| $ | 487 |
|
| $ | 276 |
|
| $ | 452 |
|
Joint interest billings |
|
| 111 |
|
|
| 110 |
|
|
| 58 |
|
|
| 168 |
|
Marketing and midstream revenues |
|
| 792 |
|
|
| 708 |
|
|
| 147 |
|
|
| 207 |
|
Other |
|
| 44 |
|
|
| 69 |
|
|
| 23 |
|
|
| 13 |
|
Gross accounts receivable |
|
| 1,475 |
|
|
| 1,374 |
|
|
| 504 |
|
|
| 840 |
|
Allowance for doubtful accounts |
|
| (13 | ) |
|
| (18 | ) |
|
| (11 | ) |
|
| (8 | ) |
Net accounts receivable |
| $ | 1,462 |
|
| $ | 1,356 |
|
| $ | 493 |
|
| $ | 832 |
|
|
|
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.
2118
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Other Intangible Assets12.Property, Plant and Equipment
The following table presents other intangible assets reported in other long-term assets in the accompanying consolidated balance sheets.aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas activities.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Customer relationships |
| $ | 1,796 |
|
| $ | 1,796 |
|
Accumulated amortization |
|
| (202 | ) |
|
| (172 | ) |
Net intangibles |
| $ | 1,594 |
|
| $ | 1,624 |
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||
Property and equipment: |
|
|
|
|
|
|
|
|
Proved |
| $ | 28,407 |
|
| $ | 27,668 |
|
Unproved and properties under development |
|
| 432 |
|
|
| 583 |
|
Total oil and gas |
|
| 28,839 |
|
|
| 28,251 |
|
Less accumulated DD&A |
|
| (24,286 | ) |
|
| (20,693 | ) |
Oil and gas property and equipment, net |
|
| 4,553 |
|
|
| 7,558 |
|
Other property and equipment |
|
| 1,746 |
|
|
| 1,725 |
|
Less accumulated DD&A |
|
| (743 | ) |
|
| (690 | ) |
Other property and equipment, net (1) |
|
| 1,003 |
|
|
| 1,035 |
|
Property and equipment, net |
| $ | 5,556 |
|
| $ | 8,593 |
|
(1) | $100 million and $80 million related to CDM in 2020 and 2019, respectively. |
The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $37 million and $29 million forDuring the three months ended September 30, 2017 and 2016, respectively, and $96 million and $87 million for thefirst nine months ended September 30, 2017of 2020, Devon recognized asset impairments of $2.7 billion primarily related to proved oil and 2016, respectively. The remaining amortization expense is estimated to be $123gas assets and $149 million of unproved impairments, which significantly reduced the carrying value of its property and equipment, net. See Note 5for each of the next five years.
additional details.
13. |
|
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 |
|
| Debt and Related Expenses |
A
See below for a summary of debt is as follows:instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.
|
| 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 |
|
|
|
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||
5.85% due December 15, 2025 |
| $ | 485 |
|
| $ | 485 |
|
7.50% due September 15, 2027 |
|
| 73 |
|
|
| 73 |
|
7.875% due September 30, 2031 |
|
| 675 |
|
|
| 675 |
|
7.95% due April 15, 2032 |
|
| 366 |
|
|
| 366 |
|
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 |
|
| (20 | ) |
|
| (20 | ) |
Debt issuance costs |
|
| (32 | ) |
|
| (35 | ) |
Total long-term debt |
| $ | 4,297 |
|
| $ | 4,294 |
|
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Devon has a $3.0 billion Senior Credit Facility. As of September 30, 2017,2020, Devon had $590 outstanding borrowings under the Senior Credit Facility and had issued $2 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.this facility. 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, 2017,2020, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.9%19.5%.
Retirement of Senior Notes
In the third quarter of 2016,January 2019, Devon completed tender offers to repurchase $1.2 billion of debt securities, using proceeds from the asset divestitures discussed in Note 2. Devon recognized a loss on early retirement of debt, primarily consisting of $82 million in cash retirement costs and other fees. 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, there were $9 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility. The General Partner has a $250 million secured revolving credit facility. As of September 30, 2017, the General Partner had $74 million in outstanding borrowings at an average rate of 3.2%. 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 $500repaid $162 million of 5.45% unsecured6.30% 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 quarterat maturity.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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 |
| ||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
| $ | 97 |
|
| $ | 120 |
|
| $ | 292 |
|
| $ | 376 |
|
Early retirement of debt |
|
| — |
|
|
| 84 |
|
|
| — |
|
|
| 84 |
|
Capitalized interest |
|
| (19 | ) |
|
| (16 | ) |
|
| (53 | ) |
|
| (47 | ) |
Other |
|
| (1 | ) |
|
| 7 |
|
|
| (3 | ) |
|
| 18 |
|
Total Devon net financing costs |
|
| 77 |
|
|
| 195 |
|
|
| 236 |
|
|
| 431 |
|
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
|
| 43 |
|
|
| 37 |
|
|
| 125 |
|
|
| 105 |
|
Interest accretion on deferred installment payment |
|
| 7 |
|
|
| 13 |
|
|
| 20 |
|
|
| 39 |
|
Early retirement of debt |
|
| — |
|
|
| — |
|
|
| (9 | ) |
|
| — |
|
Other |
|
| — |
|
|
| (2 | ) |
|
| (2 | ) |
|
| (5 | ) |
Total EnLink net financing costs |
|
| 50 |
|
|
| 48 |
|
|
| 134 |
|
|
| 139 |
|
Total net financing costs |
| $ | 127 |
|
| $ | 243 |
|
| $ | 370 |
|
| $ | 570 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Interest based on debt outstanding |
| $ | 65 |
|
| $ | 65 |
|
| $ | 195 |
|
| $ | 195 |
|
Interest income |
|
| (5 | ) |
|
| (10 | ) |
|
| (12 | ) |
|
| (28 | ) |
Other |
|
| 6 |
|
|
| 5 |
|
|
| 17 |
|
|
| 19 |
|
Total net financing costs |
| $ | 66 |
|
| $ | 60 |
|
| $ | 200 |
|
| $ | 186 |
|
2314.Leases
The following table presents Devon’s right-of-use assets and lease liabilities as of ContentsSeptember 30, 2020 and December 31, 2019.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
|
| September 30, 2020 |
|
| December 31, 2019 |
| ||||||||||||||||||
|
| Finance |
|
| Operating |
|
| Total |
|
| Finance |
|
| Operating |
|
| Total |
| ||||||
Right-of-use assets |
| $ | 222 |
|
| $ | 4 |
|
| $ | 226 |
|
| $ | 229 |
|
| $ | 14 |
|
| $ | 243 |
|
Lease liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current lease liabilities (1) |
| $ | 7 |
|
| $ | 1 |
|
| $ | 8 |
|
| $ | 7 |
|
| $ | 10 |
|
| $ | 17 |
|
Long-term lease liabilities |
|
| 243 |
|
|
| 2 |
|
|
| 245 |
|
|
| 240 |
|
|
| 4 |
|
|
| 244 |
|
Total lease liabilities |
| $ | 250 |
|
| $ | 3 |
|
| $ | 253 |
|
| $ | 247 |
|
| $ | 14 |
|
| $ | 261 |
|
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)(1)Current lease liabilities are included in other current liabilities on the consolidated balance sheets.
(Unaudited)
15. Asset Retirement ObligationsDevon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing lease assets are related to real estate.
15. | Asset Retirement Obligations |
The following table presents the changes in Devon’s asset retirement obligations.
|
| Nine Months Ended September 30, |
| |||||||||||||
|
| 2017 |
|
| 2016 |
|
| Nine Months Ended September 30, |
| |||||||
|
| (Millions) |
|
| 2020 |
|
| 2019 |
| |||||||
Asset retirement obligations as of beginning of period |
| $ | 1,272 |
|
| $ | 1,414 |
|
| $ | 398 |
|
| $ | 484 |
|
Liabilities incurred and assumed through acquisitions |
|
| 30 |
|
|
| 18 |
| ||||||||
Liabilities incurred |
|
| 15 |
|
|
| 14 |
| ||||||||
Liabilities settled and divested |
|
| (53 | ) |
|
| (310 | ) |
|
| (24 | ) |
|
| (50 | ) |
Revision of estimated obligation |
|
| (184 | ) |
|
| 70 |
|
|
| 4 |
|
|
| (62 | ) |
Accretion expense on discounted obligation |
|
| 47 |
|
|
| 58 |
|
|
| 15 |
|
|
| 16 |
|
Foreign currency translation adjustment |
|
| 29 |
|
|
| 26 |
| ||||||||
Asset retirement obligations as of end of period |
|
| 1,141 |
|
|
| 1,276 |
|
|
| 408 |
|
|
| 402 |
|
Less current portion |
|
| 41 |
|
|
| 46 |
|
|
| 10 |
|
|
| 17 |
|
Asset retirement obligations, long-term |
| $ | 1,100 |
|
| $ | 1,230 |
|
| $ | 398 |
|
| $ | 385 |
|
During the first quarternine months of 2017,2019, Devon reduced its estimated asset retirement obligations by $184$62 million, primarily due to changes in the assumed inflation ratefuture cost estimates and retirement dates for its oil and gas assets.
During Additionally, during the first nine months of 2016,2019, Devon reduced its asset retirement obligationobligations by $285$34 million for those obligations that were assumed by purchasersas a result of certain upstream U.S. assets. See the non-core asset divestitures. For additional information, see Note 2 for additional details..
16. |
|
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 |
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||||||||||||
|
| September 30, |
|
| September 30, |
|
| September 30, |
|
| September 30, |
| ||||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||||||
|
| (Millions) |
| |||||||||||||||||||||||||||||
Service cost |
| $ | 4 |
|
| $ | 3 |
|
| $ | 12 |
|
| $ | 12 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Interest cost |
|
| 11 |
|
|
| 9 |
|
|
| 32 |
|
|
| 32 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Expected return on plan assets |
|
| (14 | ) |
|
| (14 | ) |
|
| (41 | ) |
|
| (40 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Amortization of prior service cost (1) |
|
| — |
|
|
| 1 |
|
|
| 1 |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| (1 | ) |
|
| (1 | ) |
Net actuarial loss (1) |
|
| 5 |
|
|
| 6 |
|
|
| 14 |
|
|
| 19 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Net periodic benefit cost (2) |
| $ | 6 |
|
| $ | 5 |
|
| $ | 18 |
|
| $ | 25 |
|
| $ | — |
|
| $ | — |
|
| $ | (1 | ) |
| $ | (1 | ) |
|
|
(2) Net periodic benefit cost is a component of G&A in the accompanying consolidated comprehensive statements of earnings.
| Stockholders’ Equity |
Common Stock IssuedShare Repurchase Programs
In January 2016,March 2018, Devon issued approximately 23 million sharesannounced a $1.0 billion share repurchase program. In June 2018, Devon announced the expansion of common stock in conjunction with the STACK asset acquisition discussed in Note 2.
this program to $4.0 billion. In February 2016,2019, Devon issued 79 million shares of common stockannounced a further expansion to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.$5.0 billion with a December 31, 2019 expiration date. In December 2019, Devon announced a new $1.0 billion share repurchase program with a December 31, 2020 expiration date.
2420
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Under the new program, $800 million of the $1.0 billion authorization was conditioned upon the closing of the Barnett Shale divestiture for cash proceeds of at least $725 million. Since the Company received proceeds less than that amount in connection with the Barnett divestiture, we do not expect to complete repurchases in excess of $200 million in the aggregate under the existing repurchase program. Moreover, Devon has temporarily suspended its share repurchase program.
The table below provides information regarding purchases of Devon’s common stock that were made under the respective share repurchase programs (shares in thousands).
|
| Total Number of Shares Purchased |
|
| Dollar Value of Shares Purchased |
|
| Average Price Paid per Share |
| |||
$5.0 Billion Plan |
|
|
|
|
|
|
|
|
|
|
|
|
Full year 2018 |
|
| 78,149 |
|
| $ | 2,978 |
|
| $ | 38.11 |
|
First quarter 2019 |
|
| 36,141 |
|
|
| 1,024 |
|
|
| 28.33 |
|
Second quarter 2019 |
|
| 5,911 |
|
|
| 159 |
|
|
| 27.01 |
|
Third quarter 2019 |
|
| 22,137 |
|
|
| 550 |
|
|
| 24.80 |
|
Fourth quarter 2019 |
|
| 4,436 |
|
|
| 94 |
|
|
| 21.32 |
|
Total inception-to-date |
|
| 146,774 |
|
| $ | 4,805 |
|
| $ | 32.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$1.0 Billion Plan |
|
|
|
|
|
|
|
|
|
|
|
|
First quarter 2020 |
|
| 2,243 |
|
| $ | 38 |
|
| $ | 16.85 |
|
Total inception-to-date |
|
| 2,243 |
|
| $ | 38 |
|
| $ | 16.85 |
|
Dividends
The table below summarizes the dividends Devon paid on its common stock.
| 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 |
|
|
|
|
|
| Amounts |
|
| Rate Per Share |
| ||
Quarter Ended 2020: |
|
|
|
|
|
|
|
First quarter | $ | 34 |
|
| $ | 0.09 |
|
Second quarter |
| 42 |
|
| $ | 0.11 |
|
Third quarter |
| 43 |
|
| $ | 0.11 |
|
Total year-to-date | $ | 119 |
|
|
|
|
|
Quarter Ended 2019: |
|
|
|
|
|
|
|
First quarter | $ | 34 |
|
| $ | 0.08 |
|
Second quarter |
| 37 |
|
| $ | 0.09 |
|
Third quarter |
| 35 |
|
| $ | 0.09 |
|
Total year-to-date | $ | 106 |
|
|
|
|
|
In response to the depressed commodity price environment, Devon reducedraised its quarterly dividend by 22%, to $0.06$0.11 per share, beginning in the second quarter of 2016.2020. In the second quarter of 2019, Devon increased the quarterly dividend rate from $0.08 to $0.09 per share.
On August 4, 2020, Devon’s Board of Directors approved a $0.26 per share (approximately $100 million total) special dividend which was paid on October 1, 2020 to holders of record as of August 14, 2020. As of September 30, 2020, the accrued dividends payable is included as a component of accounts payable within the accompanying consolidated balance sheets.
|
|
Subsidiary Equity Transactions
EnLinkBarnett Shale
On October 1, 2020, Devon completed the sale of its Barnett Shale assets to BKV for proceeds, net of purchase price adjustments, of $490 million, including a $170 million deposit previously received in April 2020. Additionally, the agreement provides for contingent earnout payments to Devon of up to $260 million based upon future commodity prices, with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The contingent payment period commences on January 1, 2021 and has a term of four years.
21
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
In connection with the abilitysale of its Barnett Shale assets, approximately $88 million of the U.S. reporting unit goodwill was allocated to sell common unitsthe Barnett Shale assets. Additionally, Devon ceased depreciation for all property, plant and equipment classified as assets held for sale on the date the sales agreement was approved by the Board of Directors. Devon also recognized a $748 million asset impairment in the fourth quarter of 2019 related to these assets, primarily due to the difference between the net carrying value and the purchase price, net of estimated customary purchase price adjustments. Additionally, Devon recognized incremental asset impairments of $179 million and $3 million during the first quarter and third quarter of 2020, respectively. The valuation of the future contingent earnout payments included in the September 30, 2020 Barnett Shale impairment computation was $60 million. The value was derived utilizing a Monte Carlo valuation model and qualifies as a level 3 fair value measurement.
As of September 30, 2020, Devon has classified as cash restricted for discontinued operations on the consolidated balance sheets approximately $20 million of cash for obligations associated with the abandonment of certain gas processing contracts related to divestitures of other Barnett Shale assets that occurred in 2018. Cash payments for these charges total approximately $2 million per quarter.
Royalty Matter
Devon is a party to a class action pending in the United States District Court for the Northern District of Texas styled Henry Seeligson et al. v. Devon Energy Production Company, L.P., Case No. 3:16-cv-00082-K. The Seeligson class has been certified and Devon’s request to appeal the class certification was recently denied. The Seeligson class is composed of royalty interest owners under approximately 4,500 oil and gas leases covering properties in the Barnett Shale field in northern Texas. The Seeligson class alleges that Devon breached an implied duty to market by selling natural gas produced from the subject oil and gas leases to a Devon affiliate and failing to obtain the best price reasonably available for the gas. The Seeligson class alleges that this breach resulted in Devon underpaying royalties to the class during the period from January 1, 2008 through March 1, 2014. Although Devon denies the allegations asserted in the Seeligson case, in order to avoid the uncertainty of litigation, Devon recently reached an agreement in principle to settle the class claims. Although this settlement is contingent upon the negotiation and execution of a final definitive settlement agreement and subject to approval by the District Court, Devon recorded a $28 million expense for this matter in its “atthird quarter 2020 discontinued operations. The amount is included within discontinued operations in the market” equity offering programs. consolidated statements of comprehensive earnings and consolidated balance sheets.
Canada
In the second quarter of 2019, Devon completed the sale of its Canadian business for $2.6 billion ($3.4 billion Canadian dollars), net of purchase price adjustments, and recognized a pre-tax gain of $223 million ($425 million net of tax, primarily due to a significant deferred tax benefit) in 2019. Current (cash) income and withholding taxes associated with the Canadian business were approximately $175 million and were paid in the first half of 2020.The disposition of substantially all of Devon’s Canadian oil and gas assets resulted in Devon releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain computation. The historical cumulative foreign currency translation portion of the gain is not taxable.
During the third quarter of 2017, EnLink entered into additional equity distribution agreements2019, Devon utilized a portion of the sales proceeds to sell up to $600early retire $500 million of the 4.00% senior notes due July 15, 2021 and $1.0 billion of the 3.25% senior notes due May 15, 2022. Devon recognized a charge on the early retirement of these notes consisting of $52 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 monthscash retirement costs and $6 million of 2017, EnLink issued and sold 5 million common units through its programs and generated $92 million in net proceeds.noncash charges.
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.
As of September 30, 2017, Devon’s ownership interest in EnLink was 23%, excluding2020, Devon has classified as cash restricted for discontinued operations on the interest held byconsolidated balance sheets approximately $170 million of cash for obligations retained related to the General Partner. Devon’s controlling ownership interestCanadian business. The remaining obligations consist of a firm transportation agreement and office leases. Cash payments for these charges total approximately $8 million per quarter.
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents the amounts reported in the General Partnerconsolidated statements of comprehensive earnings as of September 30, 2017 was 64%. The net gains 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.discontinued operations.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| Barnett Shale |
|
| Canada |
|
| Total |
|
| Barnett Shale |
|
| Canada |
|
| Total |
| ||||||
2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
| $ | 94 |
|
| $ | — |
|
| $ | 94 |
|
| $ | 263 |
|
| $ | — |
|
| $ | 263 |
|
Total revenues |
|
| 94 |
|
|
| — |
|
|
| 94 |
|
|
| 263 |
|
|
| — |
|
|
| 263 |
|
Production expenses |
|
| 66 |
|
|
| — |
|
|
| 66 |
|
|
| 214 |
|
|
| — |
|
|
| 214 |
|
Asset impairments |
|
| 3 |
|
|
| — |
|
|
| 3 |
|
|
| 182 |
|
|
| — |
|
|
| 182 |
|
Asset dispositions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2 | ) |
|
| (2 | ) |
General and administrative expenses |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| — |
|
|
| 3 |
|
|
| 3 |
|
Financing costs, net |
|
| — |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
|
|
| (3 | ) |
|
| (3 | ) |
Other expenses |
|
| 27 |
|
|
| (1 | ) |
|
| 26 |
|
|
| 16 |
|
|
| 3 |
|
|
| 19 |
|
Total expenses |
|
| 96 |
|
|
| — |
|
|
| 96 |
|
|
| 412 |
|
|
| 1 |
|
|
| 413 |
|
Earnings (loss) from discontinued operations before income taxes |
|
| (2 | ) |
|
| — |
|
|
| (2 | ) |
|
| (149 | ) |
|
| (1 | ) |
|
| (150 | ) |
Income tax benefit |
|
| — |
|
|
| (15 | ) |
|
| (15 | ) |
|
| (32 | ) |
|
| (15 | ) |
|
| (47 | ) |
Net earnings (loss) from discontinued operations, net of tax |
| $ | (2 | ) |
| $ | 15 |
|
| $ | 13 |
|
| $ | (117 | ) |
| $ | 14 |
|
| $ | (103 | ) |
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, gas and NGL sales |
| $ | 101 |
|
| $ | 11 |
|
| $ | 112 |
|
| $ | 365 |
|
| $ | 741 |
|
| $ | 1,106 |
|
Oil, gas and NGL derivatives |
|
| — |
|
|
| (18 | ) |
|
| (18 | ) |
|
| — |
|
|
| (113 | ) |
|
| (113 | ) |
Marketing and midstream revenues |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 38 |
|
|
| 38 |
|
Total revenues |
|
| 101 |
|
|
| (7 | ) |
|
| 94 |
|
|
| 365 |
|
|
| 666 |
|
|
| 1,031 |
|
Production expenses |
|
| 75 |
|
|
| (1 | ) |
|
| 74 |
|
|
| 232 |
|
|
| 293 |
|
|
| 525 |
|
Exploration expenses |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| 13 |
|
Marketing and midstream expenses |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 18 |
|
|
| 18 |
|
Depreciation, depletion and amortization |
|
| 20 |
|
|
| — |
|
|
| 20 |
|
|
| 60 |
|
|
| 128 |
|
|
| 188 |
|
Asset impairments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 37 |
|
|
| 37 |
|
Asset dispositions |
|
| (1 | ) |
|
| (34 | ) |
|
| (35 | ) |
|
| 1 |
|
|
| (223 | ) |
|
| (222 | ) |
General and administrative expenses |
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| — |
|
|
| 33 |
|
|
| 33 |
|
Financing costs, net |
|
| — |
|
|
| 59 |
|
|
| 59 |
|
|
| — |
|
|
| 85 |
|
|
| 85 |
|
Restructuring and transaction costs |
|
| — |
|
|
| 5 |
|
|
| 5 |
|
|
| — |
|
|
| 244 |
|
|
| 244 |
|
Other expenses |
|
| 3 |
|
|
| 5 |
|
|
| 8 |
|
|
| 9 |
|
|
| 8 |
|
|
| 17 |
|
Total expenses |
|
| 97 |
|
|
| 36 |
|
|
| 133 |
|
|
| 302 |
|
|
| 636 |
|
|
| 938 |
|
Earnings from discontinued operations before income taxes |
|
| 4 |
|
|
| (43 | ) |
|
| (39 | ) |
|
| 63 |
|
|
| 30 |
|
|
| 93 |
|
Income tax expense (benefit) |
|
| 1 |
|
|
| (13 | ) |
|
| (12 | ) |
|
| 13 |
|
|
| (298 | ) |
|
| (285 | ) |
Net earnings from discontinued operations, net of tax |
| $ | 3 |
|
| $ | (30 | ) |
| $ | (27 | ) |
| $ | 50 |
|
| $ | 328 |
|
| $ | 378 |
|
Distributions to Noncontrolling Interests
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.
23
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents the carrying amounts of the assets and liabilities associated with discontinued operations on the consolidated balance sheets.
|
| As of September 30, 2020 |
|
| As of December 31, 2019 |
| ||||||||||||||||||
|
| Barnett Shale |
|
| Canada |
|
| Total |
|
| Barnett Shale |
|
| Canada |
|
| Total |
| ||||||
Cash restricted for discontinued operations |
| $ | 20 |
|
| $ | 170 |
|
| $ | 190 |
|
| $ | 25 |
|
| $ | 355 |
|
| $ | 380 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| $ | 33 |
|
| $ | — |
|
| $ | 33 |
|
| $ | 38 |
|
| $ | 1 |
|
| $ | 39 |
|
Other current assets |
|
| 6 |
|
|
| — |
|
|
| 6 |
|
|
| 5 |
|
|
| 2 |
|
|
| 7 |
|
Oil and gas property and equipment, based on successful efforts accounting, net |
|
| 590 |
|
|
| — |
|
|
| 590 |
|
|
| 751 |
|
|
| — |
|
|
| 751 |
|
Other property and equipment, net |
|
| 11 |
|
|
| — |
|
|
| 11 |
|
|
| 11 |
|
|
| — |
|
|
| 11 |
|
Goodwill |
|
| 88 |
|
|
| — |
|
|
| 88 |
|
|
| 88 |
|
|
| — |
|
|
| 88 |
|
Other long-term assets |
|
| — |
|
|
| 81 |
|
|
| 81 |
|
|
| — |
|
|
| 81 |
|
|
| 81 |
|
Total assets associated with discontinued operations |
| $ | 728 |
|
| $ | 81 |
|
| $ | 809 |
|
| $ | 893 |
|
| $ | 84 |
|
| $ | 977 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable |
| $ | 17 |
|
| $ | 3 |
|
| $ | 20 |
|
| $ | 15 |
|
| $ | 4 |
|
| $ | 19 |
|
Revenues and royalties payable |
|
| 42 |
|
|
| 3 |
|
|
| 45 |
|
|
| 44 |
|
|
| 3 |
|
|
| 47 |
|
Other current liabilities |
|
| 215 |
|
|
| 38 |
|
|
| 253 |
|
|
| 19 |
|
|
| 233 |
|
|
| 252 |
|
Asset retirement obligations |
|
| 145 |
|
|
| — |
|
|
| 145 |
|
|
| 141 |
|
|
| — |
|
|
| 141 |
|
Other long-term liabilities |
|
| 14 |
|
|
| 143 |
|
|
| 157 |
|
|
| 16 |
|
|
| 169 |
|
|
| 185 |
|
Total liabilities associated with discontinued operations |
| $ | 433 |
|
| $ | 187 |
|
| $ | 620 |
|
| $ | 235 |
|
| $ | 409 |
|
| $ | 644 |
|
| Commitments and Contingencies |
Devon is party to various legal actions arising in the normal course of business. Matters that are probable of an 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 likely 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.estimates.
25
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. TheDevon 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.matters except those detailed within Note 17.
Environmental and Other Matters
Devon is subject to certain environmental, health and safety laws and regulations including with respectrelating 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 MattersBeginning in 2013, various parishes in Louisiana filed suit against numerous oil and gas companies, including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination, subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The plaintiffs’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The plaintiffs seek, among other things, the payment of the costs necessary to clear, re-vegetate and
24
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon is involvedvigorously defending against these claims.
Various municipalities and other governmental and private parties in other variousCalifornia and the State of Delaware have filed legal proceedings incidentalagainst certain oil and gas companies, including Devon, seeking relief to its business. However,abate alleged impacts of climate change. These proceedings include far-reaching claims for monetary damages and injunctive relief. Although Devon cannot predict the ultimate outcome of these matters,Devon believes these claims to Devon’s knowledge, there were no other material pending legal proceedingsbe baseless and intends to which Devon is a party or to which any of its property is subject.vigorously defend against the proceedings.
| Fair Value Measurements |
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, cash restricted for discontinued operations, accounts receivable, other current receivables, accounts payable, other current payables, and accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at September 30, 20172020 and December 31, 2016.2019, as applicable. Therefore, such financial assets and liabilities are not presented in the following table.table. Additionally, information regarding 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 5 and Note 12, respectively..
|
|
|
|
|
|
|
|
|
| Fair Value |
| |||||
|
|
|
|
|
|
|
|
|
| Measurements Using: |
| |||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
| ||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||
|
| (Millions) |
| |||||||||||||
September 30, 2017 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 1,510 |
|
| $ | 1,510 |
|
| $ | 1,431 |
|
| $ | 79 |
|
Commodity derivatives |
| $ | 43 |
|
| $ | 43 |
|
| $ | — |
|
| $ | 43 |
|
Commodity derivatives |
| $ | (60 | ) |
| $ | (60 | ) |
| $ | — |
|
| $ | (60 | ) |
Interest rate derivatives |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
|
| $ | 1 |
|
Interest rate derivatives |
| $ | (62 | ) |
| $ | (62 | ) |
| $ | — |
|
| $ | (62 | ) |
Debt |
| $ | (10,403 | ) |
| $ | (11,480 | ) |
| $ | — |
|
| $ | (11,480 | ) |
Installment payment |
| $ | (243 | ) |
| $ | (244 | ) |
| $ | — |
|
| $ | (244 | ) |
Capital lease obligations |
| $ | (4 | ) |
| $ | (4 | ) |
| $ | — |
|
| $ | (4 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 | ) |
|
|
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| |||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
| ||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
| ||||
September 30, 2020 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 1,171 |
|
| $ | 1,171 |
|
| $ | 1,171 |
|
| $ | — |
|
Commodity derivatives |
| $ | 28 |
|
| $ | 28 |
|
| $ | — |
|
| $ | 28 |
|
Commodity derivatives |
| $ | (80 | ) |
| $ | (80 | ) |
| $ | — |
|
| $ | (80 | ) |
Debt |
| $ | (4,297 | ) |
| $ | (4,635 | ) |
| $ | — |
|
| $ | (4,635 | ) |
December 31, 2019 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash equivalents |
| $ | 702 |
|
| $ | 702 |
|
| $ | 702 |
|
| $ | — |
|
Commodity derivatives |
| $ | 50 |
|
| $ | 50 |
|
| $ | — |
|
| $ | 50 |
|
Commodity derivatives |
| $ | (31 | ) |
| $ | (31 | ) |
| $ | — |
|
| $ | (31 | ) |
Debt |
| $ | (4,294 | ) |
| $ | (5,376 | ) |
| $ | — |
|
| $ | (5,376 | ) |
26
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. Thethe fair value approximates the carrying value.
Level 2 Fair Value Measurements
Cash equivalents
Commodity derivatives – 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 areis 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 consistently trade 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 balancematurity when active trading 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.not available.
|
|
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.
2725
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| U.S. |
|
| Canada |
|
| EnLink |
|
| Eliminations |
|
| Total |
| |||||
|
| (Millions) |
| |||||||||||||||||
Three Months Ended September 30, 2017: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from external customers |
| $ | 1,575 |
|
| $ | 358 |
|
| $ | 1,223 |
|
| $ | — |
|
| $ | 3,156 |
|
Asset dispositions and other |
| $ | 1 |
|
| $ | — |
|
| $ | (1 | ) |
| $ | — |
|
| $ | — |
|
Intersegment revenues |
| $ | — |
|
| $ | — |
|
| $ | 174 |
|
| $ | (174 | ) |
| $ | — |
|
Depreciation, depletion and amortization |
| $ | 195 |
|
| $ | 63 |
|
| $ | 142 |
|
| $ | — |
|
| $ | 400 |
|
Interest expense |
| $ | 82 |
|
| $ | 17 |
|
| $ | 49 |
|
| $ | (15 | ) |
| $ | 133 |
|
Asset impairments |
| $ | — |
|
| $ | — |
|
| $ | 2 |
|
| $ | — |
|
| $ | 2 |
|
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 |
|
Income tax expense |
| $ | 5 |
|
| $ | 159 |
|
| $ | 7 |
|
| $ | — |
|
| $ | 171 |
|
Net earnings (loss) |
| $ | 1,117 |
|
| $ | (122 | ) |
| $ | 12 |
|
| $ | — |
|
| $ | 1,007 |
|
Net earnings attributable to noncontrolling interests |
| $ | — |
|
| $ | — |
|
| $ | 14 |
|
| $ | — |
|
| $ | 14 |
|
Net earnings (loss) attributable to Devon |
| $ | 1,117 |
|
| $ | (122 | ) |
| $ | (2 | ) |
| $ | — |
|
| $ | 993 |
|
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 |
|
Total assets |
| $ | 13,302 |
|
| $ | 3,761 |
|
| $ | 10,548 |
|
| $ | (52 | ) |
| $ | 27,559 |
|
Capital expenditures, including acquisitions |
| $ | 1,460 |
|
| $ | 275 |
|
| $ | 636 |
|
| $ | — |
|
| $ | 2,371 |
|
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 |
|
28
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 and capital resources and uses for the three-month and nine-month periods ended September 30, 20172020 compared to the three-month and nine-monthprevious periods ended September 30, 2016 and in our financial condition and liquidity since December 31, 2016.2019. For information regarding our critical accounting policies and estimates, see our 20162019 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
OverviewCOVID – 19
A novel strain of 2017 Results
Key componentscoronavirus, SARS-CoV-2, causing a disease referred to as COVID-19, was reported to have surfaced in China in late 2019 and has subsequently spread to multiple countries worldwide, resulting in a global pandemic and health crisis. Devon began actively monitoring COVID-19 in January 2020 and formally established a COVID-19 cross-functional planning team at the beginning of March. The COVID-19 team is focused on two key priorities: the health and safety of our financial performance are summarized below.employees and contractors and the uninterrupted operation of our business.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, (3) |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
|
| (Millions, except per share amounts) |
| |||||||||||||||||||||
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
|
| - 77 | % |
| $ | 1,218 |
|
| $ | (3,633 | ) |
|
| N/M |
|
Net earnings (loss) per diluted share attributable to Devon |
| $ | 0.43 |
|
| $ | 1.89 |
|
|
| - 77 | % |
| $ | 2.31 |
|
| $ | (7.22 | ) |
|
| N/M |
|
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 |
|
Retained production (MBoe/d) |
|
| 527 |
|
|
| 550 |
|
|
| - 4 | % |
|
| 542 |
|
|
| 578 |
|
|
| - 6 | % |
Total production (MBoe/d) |
|
| 527 |
|
|
| 577 |
|
|
| - 9 | % |
|
| 542 |
|
|
| 635 |
|
|
| - 15 | % |
Realized price per Boe (2) |
| $ | 25.67 |
|
| $ | 20.98 |
|
|
| +22 | % |
| $ | 25.41 |
|
| $ | 17.37 |
|
|
| +46 | % |
Operating cash flow |
| $ | 776 |
|
| $ | 727 |
|
|
| +7 | % |
| $ | 2,420 |
|
| $ | 1,237 |
|
|
| +96 | % |
Capital expenditures, including acquisitions |
| $ | 833 |
|
| $ | 457 |
|
|
| +82 | % |
| $ | 2,371 |
|
| $ | 3,428 |
|
|
| - 31 | % |
Shareholder and noncontrolling interests distributions |
| $ | 114 |
|
| $ | 109 |
|
|
| +5 | % |
| $ | 342 |
|
| $ | 414 |
|
|
| - 17 | % |
Cash and cash equivalents |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 2,781 |
|
| $ | 2,385 |
|
|
| +17 | % |
Total debt |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 10,403 |
|
| $ | 11,354 |
|
|
| - 8 | % |
• | Health and safety – The COVID-19 team has developed and implemented a number of safety measures, which have successfully kept our workforce healthy and safe. The COVID-19 team has established an informational campaign to provide employees an understanding of the virus risk factors and safety measures, as well as timely updates from governmental stay-at-home regulations. Expectations have also been set for employees to communicate immediately if they, or someone they have been in contact with, has experienced symptoms or tested positive for COVID-19. Other measures have included closing all of Devon’s office buildings and locations to the public, implementing social distancing and encouraging employees to work from home. Beginning in late March, more than 90% of the workforce assigned to Devon’s Oklahoma City Headquarters office were primarily working from home until the vast majority returned to the office late in the second quarter. The COVID-19 team also strongly encourages employees to wear masks, reinforces social distancing measures and continues to perform targeted and routine intensive and deep cleaning of all Devon office locations. |
|
| Uninterrupted operation of our business – Beyond workforce safety measures, the COVID-19 team has worked with government officials to ensure our business continues to be deemed an essential business or infrastructure. The COVID-19 team has ensured technology and |
This outbreak and the related responses of governmental authorities and others to limit the spread of the virus have significantly reduced global economic activity, resulting in an unprecedented decline in the demand for oil and other commodities. This supply-and-demand imbalance was exacerbated by uncertainty regarding the future global supply of oil due to disputes between Russia and the members of OPEC in March 2020. These factors caused a swift and material deterioration in commodity prices in early 2020, with NYMEX WTI oil prices falling from a high of over $60/Bbl at the beginning of the year to below $20/Bbl in April 2020. By the end of the second quarter of 2020, NYMEX WTI oil prices recovered to approximately $40/Bbl and may remain volatile around this level for the foreseeable future.
On September 26, 2020, we entered into the Merger Agreement, providing for an all-stock merger of equals with WPX. The Merger will create a leading unconventional oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of the Delaware Basin. This strategic combination accelerates our transition to a cash-return business model, including the implementation of a fixed plus variable dividend strategy. We remain focused on building economic value by executing on our strategic priorities of disciplined oil volume growth while cutting operational and corporate costs, reducing reinvestment rates to maximize free cash flow, maintaining low leverage, delivering cash returns to our shareholders and pursuing ESG excellence. Our recent performance highlights for these priorities include the following items:
• | Efficiency gains drove third quarter capital expenditures 3% below our plan |
|
| Third-quarter oil |
|
| Operating costs continued to decline in the third quarter of 2020, led by a 30% and 8% decrease from the year ago quarter for |
• | Reduced workforce to reflect lower and sustainable capital investment program |
• | Exited the third quarter with $4.9 billion of |
• | Closed on the Barnett Shale transaction on October 1, 2020, receiving net proceeds of $490 million |
• | Paid a special dividend of $0.26 per share for approximately $100 million on October 1, 2020 |
26
DuringOverview of 2020 Results
We operate under a disciplined returns-driven strategy focused on delivering strong operational results, financial strength and value to our shareholders and continuing our commitment to environmental, social and governance excellence, which provides us with a strong foundation to grow returns, margin and profitability. We continue to execute on our strategy and navigate through the challenged economic environment by protecting our financial strength, tailoring our capital investment to market conditions, improving our cash cost structure and preserving operational continuity.
Trends of our quarterly earnings, operating cash flow, EBITDAX and capital expenditures are shown below. The quarterly earnings chart presents amounts pertaining to both Devon’s continuing and discontinuing operations. The quarterly cash flow chart presents amounts pertaining to Devon’s continuing operations. “Core earnings” and “EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures, including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 2.
Our net earnings in recent quarters have been significantly impacted by divestiture transactions, asset impairments and temporary, noncash adjustments to the value of our commodity hedges. Net earnings in the third quarter of 2020 included a $0.1 billion hedge valuation loss, net of tax. Net earnings in the second quarter of 2020 included a $0.5 billion hedge valuation loss, net of tax. Net earnings in the first nine monthsquarter of 2017, we generated solid operating2020 included $2.3 billion of asset impairments on our proved and unproved properties and a $0.5 billion hedge valuation gain, both net of taxes. Net earnings in the fourth quarter of 2019 included $0.6 billion of asset impairments and a $0.1 billion hedge valuation loss, both net of taxes.Excluding these amounts, our core earnings have been more stable over recent quarters but continue to be heavily influenced by commodity prices.
Despite our portfolio enhancements, aggressive cost reductions and operational advancements, our financial results with our three-fold strategywere challenged by commodity prices and deterioration of operatingthe macro-economic environment resulting from the unprecedented COVID-19 pandemic. Our earnings increased from the second quarter of 2020 to the third quarter of 2020 due to an increase in North America’s best resource plays, delivering superior execution and maintaining a high degree of financial strength.overall commodity prices. Led by a 44% increase in WTI from the second quarter of 2020 to the third quarter of 2020, our development inunhedged combined realized price rose 57%, while our hedged price increased 3%. In response to this commodity price environment, we were able to reduce our aggregate production and G&A expenses 14% compared to the STACK, 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.year ago quarter.
Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s27
Like earnings, our operating margins, earnings and cash flow duringis sensitive to volatile commodity prices. EBITDAX, which excludes financial amounts related to discontinued operations, and operating cash flows continue to be impacted from the first nine months of 2017. COVID-19 pandemic and declines in commodity prices. As operating cash flow has declined, we have reduced our 2020 capital development plans approximately $800 million, or 45% compared to the original capital budget.
We exited the third quarter of 20172020 with $4.9 billion of liquidity comprised of $2.8$1.9 billion of cash, inclusive of $190 million of cash restricted for discontinued operations, and $2.9$3.0 billion of available credit under our Senior Credit Facility. We have $4.3 billion of debt outstanding with no significant debt maturities until 2021. At September 30, 2017, we also hadthe end of 2025. We currently have approximately 65%50% and 40% of the first half of our remaining 2017 forecasted2021 oil production hedged at an average floor price of $50/Bbl and approximately 66% of our remaining 2017 forecasted natural gas production hedged, atrespectively. These contracts consist of collars and swaps based off the WTI oil benchmark and the Henry Hub natural gas index. Additionally, we have entered into regional basis swaps in an average flooreffort to protect price realizations across our portfolio.
Results of $3.10/MMBtu. We are building our 2018 and 2019 hedge positions at similar prices.Operations
We expectThe following graphs, discussion and analysis are intended to further enhanceprovide an understanding of our results of operations and current financial strength with our announced $1 billion asset divestiture program. The planned divestitures include select portionscondition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests. Analysis of the Barnett Shale focused primarilychange in net earnings from continuing operations is shown below 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 $400analysis of the change in net earnings from discontinued operations is shown on page 36.
Continuing Operations |
Q3 2020 vs. Q2 2020
Our third quarter 2020 net loss from continuing operations was $103 million, under this program.compared to a net loss of $677 million for the second quarter of 2020. The graph below shows the change in the net loss from the second quarter of 2020 to the third quarter of 2020. The material changes are further discussed by category on the following pages.
2928
We 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:
Production Volumes
|
|
|
|
|
|
|
|
|
|
30
Oil, Gas and NGL Production
|
| 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 | % |
31
|
| 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 | % |
|
|
| Q3 2020 |
|
| % of Total |
|
| Q2 2020 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 77 |
|
|
| 53 | % |
|
| 79 |
|
|
| - 3 | % |
Powder River Basin |
|
| 21 |
|
|
| 14 | % |
|
| 18 |
|
|
| +14 | % |
Eagle Ford |
|
| 22 |
|
|
| 15 | % |
|
| 27 |
|
|
| - 19 | % |
Anadarko Basin |
|
| 19 |
|
|
| 13 | % |
|
| 21 |
|
|
| - 9 | % |
Other |
|
| 7 |
|
|
| 5 | % |
|
| 8 |
|
|
| - 9 | % |
Total |
|
| 146 |
|
|
| 100 | % |
|
| 153 |
|
|
| - 5 | % |
|
|
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, 2017 and 2016.
|
| 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 |
|
|
| Q3 2020 |
|
| % of Total |
|
| Q2 2020 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 239 |
|
|
| 41 | % |
|
| 241 |
|
|
| - 1 | % |
Powder River Basin |
|
| 23 |
|
|
| 4 | % |
|
| 20 |
|
|
| +12 | % |
Eagle Ford |
|
| 73 |
|
|
| 12 | % |
|
| 87 |
|
|
| - 16 | % |
Anadarko Basin |
|
| 242 |
|
|
| 42 | % |
|
| 262 |
|
|
| - 8 | % |
Other |
|
| 3 |
|
|
| 1 | % |
|
| 4 |
|
|
| - 13 | % |
Total |
|
| 580 |
|
|
| 100 | % |
|
| 614 |
|
|
| - 6 | % |
|
| Q3 2020 |
|
| % of Total |
|
| Q2 2020 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 38 |
|
|
| 46 | % |
|
| 29 |
|
|
| +32 | % |
Powder River Basin |
|
| 3 |
|
|
| 3 | % |
|
| 2 |
|
|
| +19 | % |
Eagle Ford |
|
| 11 |
|
|
| 14 | % |
|
| 12 |
|
|
| - 1 | % |
Anadarko Basin |
|
| 30 |
|
|
| 36 | % |
|
| 25 |
|
|
| +18 | % |
Other |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 2 | % |
Total |
|
| 83 |
|
|
| 100 | % |
|
| 69 |
|
|
| +20 | % |
Commodity sales increased
|
| Q3 2020 |
|
| % of Total |
|
| Q2 2020 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 155 |
|
|
| 48 | % |
|
| 149 |
|
|
| +4 | % |
Powder River Basin |
|
| 28 |
|
|
| 9 | % |
|
| 24 |
|
|
| +14 | % |
Eagle Ford |
|
| 46 |
|
|
| 14 | % |
|
| 53 |
|
|
| - 14 | % |
Anadarko Basin |
|
| 89 |
|
|
| 27 | % |
|
| 90 |
|
|
| - 1 | % |
Other |
|
| 8 |
|
|
| 2 | % |
|
| 9 |
|
|
| - 8 | % |
Total |
|
| 326 |
|
|
| 100 | % |
|
| 325 |
|
|
| +0 | % |
From the second quarter of 2020 to the third quarter of 2020, the change in volumes contributed to a $3 million decrease in earnings. Due to 2020 capital expenditures being reduced by 45% in response to the challenged current macro-economic environment and the timing of completions, volumes continued to remain lower in the third quarter. Volumes for the fourth quarter are expected to range from approximately 318 to 334 MBoe/d.
Field Prices
|
| Q3 2020 |
|
| Realization |
|
| Q2 2020 |
|
| Change |
| ||||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 40.86 |
|
|
|
|
|
| $ | 28.42 |
|
|
| +44 | % |
Realized price, unhedged |
| $ | 37.56 |
|
| 92% |
|
| $ | 21.25 |
|
|
| +77 | % | |
Cash settlements |
| $ | 0.65 |
|
|
|
|
|
| $ | 15.25 |
|
|
|
|
|
Realized price, with hedges |
| $ | 38.21 |
|
| 94% |
|
| $ | 36.50 |
|
|
| +5 | % |
|
| Q3 2020 |
|
| Realization |
|
| Q2 2020 |
|
| Change |
| ||||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 1.98 |
|
|
|
|
|
| $ | 1.71 |
|
|
| +16 | % |
Realized price, unhedged |
| $ | 1.48 |
|
| 75% |
|
| $ | 1.29 |
|
|
| +14 | % | |
Cash settlements |
| $ | 0.06 |
|
|
|
|
|
| $ | 0.28 |
|
|
|
|
|
Realized price, with hedges |
| $ | 1.54 |
|
| 78% |
|
| $ | 1.57 |
|
|
| - 2 | % |
|
| Q3 2020 |
|
| Realization |
|
| Q2 2020 |
|
| Change |
| ||||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 16.69 |
|
|
|
|
|
| $ | 12.57 |
|
|
| +33 | % |
Realized price, unhedged |
| $ | 12.36 |
|
| 74% |
|
| $ | 8.89 |
|
|
| +39 | % | |
Cash settlements |
| $ | (0.30 | ) |
|
|
|
|
| $ | 0.51 |
|
|
|
|
|
Realized price, with hedges |
| $ | 12.06 |
|
| 72% |
|
| $ | 9.40 |
|
|
| +28 | % |
(1)Based upon composition of our NGL barrel.
|
| Q3 2020 |
|
| Q2 2020 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
| $ | 22.60 |
|
| $ | 14.37 |
|
|
| +57 | % |
Cash settlements |
| $ | 0.33 |
|
| $ | 7.83 |
|
|
|
|
|
Realized price, with hedges |
| $ | 22.93 |
|
| $ | 22.20 |
|
|
| +3 | % |
From the second quarter of 2020 to the third quarter of 2020, field prices contributed to a $257 million increase in earnings. Unhedged realized oil, gas and the first nine months of 2017NGL prices increased primarily due to price increases for all commodities.higher WTI, Henry Hub and Mont Belvieu index prices. 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.
The increases in sales due to the favorable movement in commodity prices was partially offset by a declinedecrease in production volumes. In 2016, we significantly reduced our drilling and completion capital programs in responsehedge cash settlements related to depressed commodity prices. Consequently, productionall products from our retained U.S. assets, other than STACK, steadily declined throughout 2016 and into 2017. Our 2016 asset divestiture program also caused our volumesthe second quarter to decline significantly in the third and fourth quartersquarter of 2016. Additionally, Hurricane Harvey negatively impacted our third quarter 2017 production in2020.
We currently have approximately 50% of the Eagle Ford as we temporarily suspended operations.
32
A summaryfirst half of our open commodity derivative positions is included in Note 3 to2021 oil production hedged with an average floor price of $39/Bbl and approximately 40% of the financial statements included in “Part I. Financial Information – Item 1. Financial Statements” of this report. The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and fair value gains and losses recognized as componentshalf of our revenues. The subsequent tables present2021 gas production hedged with an average floor price of $2.45/Mcf. We are continuing to build our oil, gas2021 and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of fair value gains and losses.2022 hedge positions at market prices.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| 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 | ) |
Hedge Settlements
|
| 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 |
|
|
|
| Q3 2020 |
|
| Q2 2020 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
|
|
| |
Oil |
| $ | 9 |
|
| $ | 213 |
|
|
| - 96 | % |
Natural gas |
|
| 4 |
|
|
| 15 |
|
|
| - 73 | % |
NGL |
|
| (3 | ) |
|
| 4 |
|
|
| - 175 | % |
Total cash settlements (1) |
| $ | 10 |
|
| $ | 232 |
|
|
| - 96 | % |
(1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings. |
33
Cash settlements as presented in the tables above represent realized gains or losses related to variousthe instruments described in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
29
Production Expenses
|
| Q3 2020 |
|
| Q2 2020 |
|
| Change |
| |||
LOE |
| $ | 100 |
|
| $ | 108 |
|
|
| - 7 | % |
Gathering, processing & transportation |
|
| 125 |
|
|
| 123 |
|
|
| +2 | % |
Production taxes |
|
| 42 |
|
|
| 25 |
|
|
| +68 | % |
Property taxes |
|
| 4 |
|
|
| 7 |
|
|
| - 38 | % |
Total |
| $ | 271 |
|
| $ | 263 |
|
|
| +3 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 3.32 |
|
| $ | 3.69 |
|
|
| - 10 | % |
Gathering, processing & transportation |
| $ | 4.17 |
|
| $ | 4.16 |
|
|
| +0 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 6.2 | % |
|
| 5.9 | % |
|
| +4 | % |
Production expenses increased from the second quarter to the third quarter primarily due to increased production taxes resulting from higher oil, gas and NGL sales.
Field-Level Cash Margin
The table below presents the field-level cash margin for each of our operating areas. Field-level cash margin is computed as oil, gas and NGL sales less production expenses and is not prepared in accordance with GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, field prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
| Q3 2020 |
|
| $ per BOE |
|
| Q2 2020 |
|
| $ per BOE |
| ||||
Field-level cash margin (non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
| $ | 236 |
|
| $ | 16.52 |
|
| $ | 106 |
|
| $ | 7.81 |
|
Powder River Basin |
|
| 47 |
|
| $ | 18.63 |
|
|
| 20 |
|
| $ | 9.09 |
|
Eagle Ford |
|
| 61 |
|
| $ | 14.66 |
|
|
| 22 |
|
| $ | 4.50 |
|
Anadarko Basin |
|
| 56 |
|
| $ | 6.72 |
|
|
| 13 |
|
| $ | 1.67 |
|
Other |
|
| 7 |
|
| $ | 10.10 |
|
|
| — |
|
| $ | 0.10 |
|
Total |
| $ | 407 |
|
| $ | 13.59 |
|
| $ | 161 |
|
| $ | 5.45 |
|
Due to higher commodity derivatives. In additionbenchmark prices, our unhedged realized price per Boe increased 57% from the second quarter to the third quarter of 2020. These higher realizations improved our field-level cash settlements, we alsomargin and other performance measures.
Other Items
|
| Q3 2020 |
|
| Q2 2020 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | (97 | ) |
| $ | (593 | ) |
| $ | 496 |
|
Marketing and midstream operations |
|
| (2 | ) |
|
| (8 | ) |
|
| 6 |
|
Exploration expenses |
|
| 39 |
|
|
| 12 |
|
|
| (27 | ) |
Net financing costs |
|
| 66 |
|
|
| 69 |
|
|
| 3 |
|
Restructuring and transaction costs |
|
| 32 |
|
|
| — |
|
|
| (32 | ) |
Other expenses |
|
| — |
|
|
| 13 |
|
|
| 13 |
|
|
|
|
|
|
|
|
|
|
| $ | 459 |
|
(1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings. |
We 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 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 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 | % |
The overall increase 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,additional information, see Note 23 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
Lease Operating Expenses
|
| 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 | % |
Total LOE and LOE per Boe increased during the third quarter of 2017 primarily due to higher transportation of $38 million resulting from tolls on Canada’s Access Pipeline of $27 million, which commenced 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 due to our non-core U.S. property divestitures during 2016 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 offset by Access Pipeline transportation tolls of $87 million during the first nine months of 2017, which was the primary driver of the increase in total LOE per Boe.
34
General and Administrative Expenses
|
| 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 | % |
Gross G&A increased during the third quarter of 2017 due 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
|
| 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 | % |
Production taxes increased during each period in 2017 on an absolute dollar basis primarily due to an increase in our U.S. 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 assessmentsExploration expenses increased 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 Amortization
|
| 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 | % |
35
DD&A from our oil and gas properties decreased insecond quarter to the third quarter primarily due to lower production and decreased during the first nine monthsunproved impairments of 2017 largely due to lower DD&A rates, resulting from the oil and gas asset impairments and non-core U.S. divestures$36 million 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 Impairments
During the third quarter and the first nine months of 2016,related to certain non-core acreage we recognized asset impairments totaling $319 million and $4.9 billion, respectively.no longer intend to pursue for exploration opportunities. For further discussion,additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
Restructuring and Transaction Costs
During the first nine months of 2016, we recognized restructuring costs of $249 million as a result of a reduction in workforce driven by our cost reduction initiatives and divestiture of non-core properties.
During the first nine months of 2016, we recognized transaction costs of $17 million, primarily associated withreflect workforce reductions that occurred in the closing ofthird quarter to improve the acquisitions discussed in company’s cost structure and enhance its operational focus. For additional information, see Note 26 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
Net Financing Costs
Income Taxes
|
| 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 | % |
|
| Q3 2020 |
|
| Q2 2020 |
| ||
Current benefit |
| $ | (90 | ) |
| $ | (3 | ) |
Deferred benefit |
|
| — |
|
|
| — |
|
Total benefit |
| $ | (90 | ) |
| $ | (3 | ) |
Effective income tax rate |
|
| 47 | % |
|
| 0 | % |
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 interestFor discussion 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 income taxes, see Note 147 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
30
Income Taxes2020 vs. 2019
The following graphs, discussion and analysis are intended to provide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of earnings attributable to noncontrolling interests.
Q3 2020 vs. Q3 2019
Our third quarter 2020 net loss from continuing operations was $103 million, compared to net earnings of $136 million in the third quarter of 2019. The graph below shows the change in the net earnings from the third quarter of 2019 to the net loss in the third quarter of 2020. The material changes are further discussed on the following pages.
September 30, YTD 2020 vs. September 30, YTD 2019
Our nine months ended September 30, 2020 net loss from continuing operations was $2.5 billion, compared to a net loss of $91 million for the nine months ended September 30, 2019. The graph below shows the change in the net loss from the nine months ended September 30, 2019 to the nine months ended September 30, 2020. The material changes are further discussed on the following pages.
31
Production Volumes
|
| 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 | % |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||||||||
|
| 2020 |
|
| % of Total |
|
| 2019 |
|
| Change |
|
| 2020 |
|
| % of Total |
|
| 2019 |
|
| Change |
| ||||||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 77 |
|
|
| 53 | % |
|
| 70 |
|
|
| +9 | % |
|
| 80 |
|
|
| 52 | % |
|
| 66 |
|
|
| +22 | % |
Powder River Basin |
|
| 21 |
|
|
| 14 | % |
|
| 18 |
|
|
| +16 | % |
|
| 20 |
|
|
| 13 | % |
|
| 16 |
|
|
| +24 | % |
Eagle Ford |
|
| 22 |
|
|
| 15 | % |
|
| 22 |
|
|
| - 0 | % |
|
| 25 |
|
|
| 16 | % |
|
| 23 |
|
|
| +7 | % |
Anadarko Basin |
|
| 19 |
|
|
| 13 | % |
|
| 32 |
|
|
| - 40 | % |
|
| 21 |
|
|
| 14 | % |
|
| 32 |
|
|
| - 33 | % |
Other |
|
| 7 |
|
|
| 5 | % |
|
| 9 |
|
|
| - 25 | % |
|
| 8 |
|
|
| 5 | % |
|
| 8 |
|
|
| - 9 | % |
Total |
|
| 146 |
|
|
| 100 | % |
|
| 151 |
|
|
| - 4 | % |
|
| 154 |
|
|
| 100 | % |
|
| 145 |
|
|
| +6 | % |
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 239 |
|
|
| 41 | % |
|
| 167 |
|
|
| +43 | % |
|
| 241 |
|
|
| 40 | % |
|
| 157 |
|
|
| +53 | % |
Powder River Basin |
|
| 23 |
|
|
| 4 | % |
|
| 28 |
|
|
| - 18 | % |
|
| 24 |
|
|
| 4 | % |
|
| 23 |
|
|
| +5 | % |
Eagle Ford |
|
| 73 |
|
|
| 12 | % |
|
| 75 |
|
|
| - 2 | % |
|
| 82 |
|
|
| 13 | % |
|
| 80 |
|
|
| +3 | % |
Anadarko Basin |
|
| 242 |
|
|
| 42 | % |
|
| 317 |
|
|
| - 24 | % |
|
| 258 |
|
|
| 42 | % |
|
| 321 |
|
|
| - 19 | % |
Other |
|
| 3 |
|
|
| 1 | % |
|
| 4 |
|
|
| - 14 | % |
|
| 4 |
|
|
| 1 | % |
|
| 5 |
|
|
| - 33 | % |
Total |
|
| 580 |
|
|
| 100 | % |
|
| 591 |
|
|
| - 2 | % |
|
| 609 |
|
|
| 100 | % |
|
| 586 |
|
|
| +4 | % |
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 38 |
|
|
| 46 | % |
|
| 28 |
|
|
| +37 | % |
|
| 35 |
|
|
| 45 | % |
|
| 26 |
|
|
| +35 | % |
Powder River Basin |
|
| 3 |
|
|
| 3 | % |
|
| 2 |
|
|
| +10 | % |
|
| 3 |
|
|
| 3 | % |
|
| 2 |
|
|
| +23 | % |
Eagle Ford |
|
| 11 |
|
|
| 14 | % |
|
| 11 |
|
|
| +6 | % |
|
| 11 |
|
|
| 14 | % |
|
| 12 |
|
|
| - 7 | % |
Anadarko Basin |
|
| 30 |
|
|
| 36 | % |
|
| 37 |
|
|
| - 18 | % |
|
| 28 |
|
|
| 37 | % |
|
| 37 |
|
|
| - 22 | % |
Other |
|
| 1 |
|
|
| 1 | % |
|
| 1 |
|
|
| - 46 | % |
|
| 1 |
|
|
| 1 | % |
|
| 2 |
|
|
| - 41 | % |
Total |
|
| 83 |
|
|
| 100 | % |
|
| 79 |
|
|
| +5 | % |
|
| 78 |
|
|
| 100 | % |
|
| 79 |
|
|
| - 1 | % |
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin |
|
| 155 |
|
|
| 48 | % |
|
| 127 |
|
|
| +22 | % |
|
| 155 |
|
|
| 46 | % |
|
| 118 |
|
|
| +32 | % |
Powder River Basin |
|
| 28 |
|
|
| 9 | % |
|
| 25 |
|
|
| +9 | % |
|
| 27 |
|
|
| 8 | % |
|
| 22 |
|
|
| +21 | % |
Eagle Ford |
|
| 46 |
|
|
| 14 | % |
|
| 45 |
|
|
| +1 | % |
|
| 50 |
|
|
| 15 | % |
|
| 48 |
|
|
| +3 | % |
Anadarko Basin |
|
| 89 |
|
|
| 27 | % |
|
| 121 |
|
|
| - 26 | % |
|
| 92 |
|
|
| 28 | % |
|
| 123 |
|
|
| - 25 | % |
Other |
|
| 8 |
|
|
| 2 | % |
|
| 10 |
|
|
| - 21 | % |
|
| 9 |
|
|
| 3 | % |
|
| 10 |
|
|
| - 5 | % |
Total |
|
| 326 |
|
|
| 100 | % |
|
| 328 |
|
|
| - 1 | % |
|
| 333 |
|
|
| 100 | % |
|
| 321 |
|
|
| +4 | % |
36From the third quarter of 2019 to the third quarter of 2020, a decrease in volumes contributed to a $19 million decrease in earnings. From the nine months ended 2019 to the nine months ended 2020, an increase in volumes contributed to a $148 million increase in earnings. Continued development in the Delaware Basin and Powder River Basin has resulted in higher production volumes during 2020 compared to 2019. These increases were partially offset by significantly lower activity in the Anadarko Basin.
32
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||||||||
|
| 2020 |
|
| Realization |
|
| 2019 |
|
| Change |
|
| 2020 |
|
| Realization |
|
| 2019 |
|
| Change |
| ||||||||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI index |
| $ | 40.86 |
|
|
|
|
|
| $ | 56.34 |
|
|
| - 27 | % |
| $ | 38.57 |
|
|
|
|
|
| $ | 57.02 |
|
|
| - 32 | % |
Realized price, unhedged |
| $ | 37.56 |
|
| 92% |
|
| $ | 54.40 |
|
|
| - 31 | % |
| $ | 34.63 |
|
| 90% |
|
| $ | 54.47 |
|
|
| - 36 | % | ||
Cash settlements |
| $ | 0.65 |
|
|
|
|
|
| $ | 2.18 |
|
|
|
|
|
| $ | 7.06 |
|
|
|
|
|
| $ | 1.80 |
|
|
|
|
|
Realized price, with hedges |
| $ | 38.21 |
|
| 94% |
|
| $ | 56.58 |
|
|
| - 32 | % |
| $ | 41.69 |
|
| 108% |
|
| $ | 56.27 |
|
|
| - 26 | % | ||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Henry Hub index |
| $ | 1.98 |
|
|
|
|
|
| $ | 2.23 |
|
|
| - 11 | % |
| $ | 1.88 |
|
|
|
|
|
| $ | 2.67 |
|
|
| - 30 | % |
Realized price, unhedged |
| $ | 1.48 |
|
| 75% |
|
| $ | 1.47 |
|
|
| +0 | % |
| $ | 1.32 |
|
| 70% |
|
| $ | 1.82 |
|
|
| - 27 | % | ||
Cash settlements |
| $ | 0.06 |
|
|
|
|
|
| $ | 0.41 |
|
|
|
|
|
| $ | 0.24 |
|
|
|
|
|
| $ | 0.15 |
|
|
|
|
|
Realized price, with hedges |
| $ | 1.54 |
|
| 78% |
|
| $ | 1.88 |
|
|
| - 18 | % |
| $ | 1.56 |
|
| 83% |
|
| $ | 1.97 |
|
|
| - 21 | % | ||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mont Belvieu blended index (1) |
| $ | 16.69 |
|
|
|
|
|
| $ | 16.18 |
|
|
| +3 | % |
| $ | 14.55 |
|
|
|
|
|
| $ | 19.39 |
|
|
| - 25 | % |
Realized price, unhedged |
| $ | 12.36 |
|
| 74% |
|
| $ | 12.02 |
|
|
| +3 | % |
| $ | 10.66 |
|
| 73% |
|
| $ | 15.02 |
|
|
| - 29 | % | ||
Cash settlements |
| $ | (0.30 | ) |
|
|
|
|
| $ | 2.55 |
|
|
|
|
|
| $ | 0.25 |
|
|
|
|
|
| $ | 1.57 |
|
|
|
|
|
Realized price, with hedges |
| $ | 12.06 |
|
| 72% |
|
| $ | 14.57 |
|
|
| - 17 | % |
| $ | 10.91 |
|
| 75% |
|
| $ | 16.59 |
|
|
| - 34 | % | ||
Combined (per Boe) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized price, unhedged |
| $ | 22.60 |
|
|
|
|
|
| $ | 30.47 |
|
|
| - 26 | % |
| $ | 20.91 |
|
|
|
|
|
| $ | 31.61 |
|
|
| - 34 | % |
Cash settlements |
| $ | 0.33 |
|
|
|
|
|
| $ | 2.34 |
|
|
|
|
|
| $ | 3.76 |
|
|
|
|
|
| $ | 1.46 |
|
|
|
|
|
Total |
| $ | 22.93 |
|
|
|
|
|
| $ | 32.81 |
|
|
| - 30 | % |
| $ | 24.67 |
|
|
|
|
|
| $ | 33.07 |
|
|
| - 25 | % |
(1) | Based upon composition of our NGL barrel. |
From the third quarter of 2019 to expect low current income tax ratesthe third quarter of 2020, field prices contributed to a $222 million decrease in earnings. Unhedged realized oil prices decreased primarily due to lower WTI index prices. Additionally, hedge cash settlements decreased for each product. From the nine months ended 2019 to the nine months ended 2020, field prices contributed to a $1.0 billion decrease in earnings. Unhedged realized oil, gas and NGL prices decreased primarily due to lower WTI, Henry Hub and Mont Belvieu index prices. These decreases were partially offset by favorable hedge cash settlements across each of our products.
Hedge Settlements
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| Change |
|
| 2020 |
|
| 2019 |
|
| Change |
| ||||||
Oil |
| $ | 9 |
|
| $ | 31 |
|
|
| -71 | % |
| $ | 298 |
|
| $ | 71 |
|
|
| 320 | % |
Natural gas |
|
| 4 |
|
|
| 22 |
|
|
| -82 | % |
|
| 40 |
|
|
| 24 |
|
|
| 67 | % |
NGL |
|
| (3 | ) |
|
| 18 |
|
|
| -117 | % |
|
| 5 |
|
|
| 33 |
|
|
| -85 | % |
Total cash settlements (1) |
| $ | 10 |
|
| $ | 71 |
|
|
| -86 | % |
| $ | 343 |
|
| $ | 128 |
|
|
| 168 | % |
(1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings. |
Production Expenses
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| Change |
|
| 2020 |
|
| 2019 |
|
| Change |
| ||||||
LOE |
| $ | 100 |
|
| $ | 118 |
|
|
| - 15 | % |
| $ | 334 |
|
| $ | 342 |
|
|
| - 2 | % |
Gathering, processing & transportation |
|
| 125 |
|
|
| 112 |
|
|
| +12 | % |
|
| 378 |
|
|
| 332 |
|
|
| +14 | % |
Production taxes |
|
| 42 |
|
|
| 58 |
|
|
| - 28 | % |
|
| 123 |
|
|
| 182 |
|
|
| - 33 | % |
Property taxes |
|
| 4 |
|
|
| 6 |
|
|
| - 35 | % |
|
| 17 |
|
|
| 17 |
|
|
| +3 | % |
Total |
| $ | 271 |
|
| $ | 294 |
|
|
| - 8 | % |
| $ | 852 |
|
| $ | 873 |
|
|
| - 2 | % |
Per Boe: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOE |
| $ | 3.32 |
|
| $ | 3.90 |
|
|
| - 15 | % |
| $ | 3.66 |
|
| $ | 3.90 |
|
|
| - 6 | % |
Gathering, processing & transportation |
| $ | 4.17 |
|
| $ | 3.71 |
|
|
| +13 | % |
| $ | 4.15 |
|
| $ | 3.78 |
|
|
| +10 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production taxes |
|
| 6.2 | % |
|
| 6.3 | % |
|
| - 2 | % |
|
| 6.4 | % |
|
| 6.5 | % |
|
| - 2 | % |
33
An increase in gathering, processing and transportation costs from the nine months ended 2019 to the nine months ended 2020 was due to higher volumes and Anadarko minimum volume commitments which are set to expire at the end of 2020. These increases were offset by lower production taxes resulting from lower oil, gas and NGL sales.
Field-Level Cash Margin
The changes in production volumes, field prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||||||||
| 2020 |
|
| $ per BOE |
|
| 2019 |
|
| $ per BOE |
|
| 2020 |
|
| $ per BOE |
|
| 2019 |
|
| $ per BOE |
| ||||||||
Field-Level Cash Margin (non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Delaware Basin | $ | 236 |
|
| $ | 16.52 |
|
| $ | 284 |
|
| $ | 24.42 |
|
| $ | 602 |
|
| $ | 14.16 |
|
| $ | 785 |
|
| $ | 24.42 |
|
Powder River Basin |
| 47 |
|
| $ | 18.63 |
|
|
| 63 |
|
| $ | 27.12 |
|
|
| 121 |
|
| $ | 16.45 |
|
|
| 173 |
|
| $ | 28.55 |
|
Eagle Ford |
| 61 |
|
| $ | 14.66 |
|
|
| 100 |
|
| $ | 24.02 |
|
|
| 170 |
|
| $ | 12.54 |
|
|
| 349 |
|
| $ | 26.44 |
|
Anadarko Basin |
| 56 |
|
| $ | 6.72 |
|
|
| 157 |
|
| $ | 14.08 |
|
|
| 143 |
|
| $ | 5.62 |
|
|
| 537 |
|
| $ | 16.03 |
|
Other |
| 7 |
|
| $ | 10.10 |
|
|
| 22 |
|
| $ | 23.91 |
|
|
| 21 |
|
| $ | 8.77 |
|
|
| 57 |
|
| $ | 20.05 |
|
Total | $ | 407 |
|
| $ | 13.59 |
|
| $ | 626 |
|
| $ | 20.73 |
|
| $ | 1,057 |
|
| $ | 11.58 |
|
| $ | 1,901 |
|
| $ | 21.66 |
|
Due to lower commodity benchmark prices, our unhedged realized price per Boe decreased 34% from the nine months ended 2019 to the nine months ended 2020. These lower realizations have negatively impacted our field-level cash margin and other performance measures.
DD&A and Asset Impairments
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| Change |
|
| 2020 |
|
| 2019 |
|
| Change |
| ||||||
Oil and gas per Boe |
| $ | 9.22 |
|
| $ | 11.70 |
|
|
| - 21 | % |
| $ | 10.19 |
|
| $ | 11.72 |
|
|
| - 13 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas |
| $ | 276 |
|
| $ | 352 |
|
|
| - 22 | % |
| $ | 929 |
|
| $ | 1,028 |
|
|
| - 10 | % |
Other property and equipment |
|
| 23 |
|
|
| 29 |
|
|
| - 19 | % |
|
| 70 |
|
|
| 87 |
|
|
| - 19 | % |
Total |
| $ | 299 |
|
| $ | 381 |
|
|
| - 22 | % |
| $ | 999 |
|
| $ | 1,115 |
|
|
| - 10 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairments |
| $ | — |
|
| $ | — |
|
| N/M |
|
| $ | 2,666 |
|
| $ | — |
|
| N/M |
|
Asset impairments were $2.7 billion in the U.S. segment based on our continuing net operating loss position.first nine months of 2020 due to significant decreases in commodity prices since the end of 2019 resulting primarily from the COVID-19 pandemic. For further discussion on income taxes,additional information, see Note 75 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
DD&A decreased in the first nine months of 2020 compared to the first nine months of 2019 primarily due to lower rates resulting from impairments recorded in the first quarter of 2020. This was partially offset by higher volumes in 2020.
General and Administrative Expenses
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| Change |
|
| 2020 |
|
| 2019 |
|
| Change |
| ||||||
Labor and benefits (net of reimbursements) |
| $ | 46 |
|
| $ | 67 |
|
|
| - 32 | % |
| $ | 157 |
|
| $ | 227 |
|
|
| - 31 | % |
Non-labor |
|
| 29 |
|
|
| 40 |
|
|
| - 29 | % |
|
| 99 |
|
|
| 129 |
|
|
| - 23 | % |
Total |
| $ | 75 |
|
| $ | 107 |
|
|
| - 30 | % |
| $ | 256 |
|
| $ | 356 |
|
|
| - 28 | % |
Labor and benefits and non-labor expenses decreased primarily as a result of continued workforce reduction and cost savings initiatives. Additional initiatives are underway to decrease annualized G&A expenses by approximately $100 million by the end of 2020.
34
Other Items
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2020 |
|
| 2019 |
|
| Change in earnings |
|
| 2020 |
|
| 2019 |
|
| Change in earnings |
| ||||||
Commodity hedge valuation changes (1) |
| $ | (97 | ) |
| $ | 56 |
|
| $ | (153 | ) |
| $ | (71 | ) |
| $ | (466 | ) |
| $ | 395 |
|
Marketing and midstream operations |
|
| (2 | ) |
|
| 16 |
|
|
| (18 | ) |
|
| (28 | ) |
|
| 48 |
|
|
| (76 | ) |
Exploration expenses |
|
| 39 |
|
|
| 18 |
|
|
| (21 | ) |
|
| 163 |
|
|
| 29 |
|
|
| (134 | ) |
Asset dispositions |
|
| — |
|
|
| (1 | ) |
|
| (1 | ) |
|
| — |
|
|
| (48 | ) |
|
| (48 | ) |
Net financing costs |
|
| 66 |
|
|
| 60 |
|
|
| (6 | ) |
|
| 200 |
|
|
| 186 |
|
|
| (14 | ) |
Restructuring and transaction costs |
|
| 32 |
|
|
| 10 |
|
|
| (22 | ) |
|
| 32 |
|
|
| 73 |
|
|
| 41 |
|
Other expenses |
|
| — |
|
|
| 3 |
|
|
| 3 |
|
|
| (35 | ) |
|
| (12 | ) |
|
| 23 |
|
|
|
|
|
|
|
|
|
|
| $ | (218 | ) |
|
|
|
|
|
|
|
|
| $ | 187 |
|
(1) | Included as a component of oil, gas and NGL derivatives on the consolidated statements of comprehensive earnings. |
We 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 relationship between contract prices and the associated forward curves. For additional information, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Marketing and midstream operations decreased approximately $76 million for the first nine months ended 2020 compared to the first nine months ended 2019 primarily due to lower commodity prices resulting from the challenged macro-economic environment in 2020, as well as downstream product inventory impairments of $17 million recognized in the first quarter of 2020.
Exploration expenses increased approximately $134 million for the first nine months ended 2020 compared to the first nine months ended 2019 primarily due to $149 million in unproved asset impairments in the first nine months of 2020. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Devon recognized $32 million in restructuring and transaction costs in the third quarter of 2020 related to workforce reductions to improve the company’s cost structure and enhance its operational focus. Devon recognized $73 million in restructuring expenses during the first nine months of 2019. For additional information, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
35
Discontinued Operations |
Results of Operations – Discontinued Operations
The table below presents key components from discontinued operations for the time periods presented. Discontinued operations include the Canadian business that Devon sold in June 2019 and the Barnett Shale assets that Devon sold on October 1, 2020. For additional information on discontinued operations, see Note 17 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
|
| Three Months Ended |
|
| Nine Months Ended |
| ||||||||||||||
|
| September 30, |
|
| June 30, |
|
| September 30, |
|
| September 30, |
|
| September 30, |
| |||||
|
| 2020 |
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| |||||
Oil, gas and NGL sales |
| $ | 94 |
|
| $ | 77 |
|
| $ | 112 |
|
| $ | 263 |
|
| $ | 1,106 |
|
Oil, gas and NGL derivatives |
| $ | — |
|
| $ | — |
|
| $ | (18 | ) |
| $ | — |
|
| $ | (113 | ) |
Production expenses |
| $ | 66 |
|
| $ | 74 |
|
| $ | 74 |
|
| $ | 214 |
|
| $ | 525 |
|
Asset impairments |
| $ | 3 |
|
| $ | — |
|
| $ | — |
|
| $ | 182 |
|
| $ | 37 |
|
Asset dispositions |
| $ | — |
|
| $ | (2 | ) |
| $ | (35 | ) |
| $ | (2 | ) |
| $ | (222 | ) |
Financing costs, net |
| $ | (1 | ) |
| $ | (1 | ) |
| $ | 59 |
|
| $ | (3 | ) |
| $ | 85 |
|
Restructuring and transaction costs |
| $ | — |
|
| $ | — |
|
| $ | 5 |
|
| $ | — |
|
| $ | 244 |
|
Other expenses |
| $ | 26 |
|
| $ | (3 | ) |
| $ | 8 |
|
| $ | 19 |
|
| $ | 17 |
|
Earnings (loss) from discontinued operations before income taxes |
| $ | (2 | ) |
| $ | 9 |
|
| $ | (39 | ) |
| $ | (150 | ) |
| $ | 93 |
|
Income tax benefit |
| $ | (15 | ) |
| $ | — |
|
| $ | (12 | ) |
| $ | (47 | ) |
| $ | (285 | ) |
Net earnings (loss) from discontinued operations, net of tax |
| $ | 13 |
|
| $ | 9 |
|
| $ | (27 | ) |
| $ | (103 | ) |
| $ | 378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (MMBoe): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barnett Shale |
|
| 9 |
|
|
| 9 |
|
|
| 9 |
|
|
| 27 |
|
|
| 27 |
|
Canada |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 19 |
|
Total production |
|
| 9 |
|
|
| 9 |
|
|
| 9 |
|
|
| 27 |
|
|
| 46 |
|
Realized price, unhedged (per Boe) - Barnett Shale |
| $ | 10.94 |
|
| $ | 8.89 |
|
| $ | 12.27 |
|
| $ | 9.89 |
|
| $ | 13.25 |
|
Realized price, unhedged (per Boe) - Canada |
| N/A |
|
| N/A |
|
| N/A |
|
| N/A |
|
| $ | 38.98 |
|
Q3 2020 vs. Q2 2020
Net earnings from discontinued operations, net of tax increased $4 million from the second quarter of 2020 to the third quarter of 2020. This was primarily due to higher gas and NGL sales in the third quarter resulting from higher commodity prices, as well as a decrease to Canadian tax liabilities in the third quarter of 2020. These increases in net earnings were partially offset by a $28 million expense recognized in the third quarter of 2020 related to a Barnett Shale royalty matter.
Q3 2020 vs. Q3 2019
Net earnings (loss) from discontinued operations, net of tax increased $40 million from the third quarter of 2019 to the third quarter of 2020. Net earnings increased primarily due to a charge on the early retirement of debt in the third quarter of 2019 as Devon utilized a portion of the sale proceeds from the Canada divestiture to early retire $1.5 billion of senior notes, with no comparable charges in the third quarter of 2020.
September 30, 2020 YTD vs. September 30, 2019 YTD
Net earnings (loss) from discontinued operations, net of tax decreased $481 million for the first nine months ended September 30, 2020 compared to the first nine months ended September 30, 2019. Net earnings decreased primarily due to the divestment of Devon’s Canadian operations during the second quarter of 2019, as well as lower revenues resulting from the challenged macro-economic environment in 2020. Additionally, 2020 includes $182 million in incremental asset impairments to our Barnett Shale assets primarily related to the amended terms of the Barnett Shale sales agreement.
36
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 and nine months ended September 30, 20172020 and 2016.2019.
|
| 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 |
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Operating cash flow from continuing operations |
| $ | 427 |
|
| $ | 595 |
|
| $ | 1,106 |
|
| $ | 1,464 |
|
Divestitures of property and equipment |
|
| 1 |
|
|
| 9 |
|
|
| 29 |
|
|
| 347 |
|
Capital expenditures |
|
| (204 | ) |
|
| (526 | ) |
|
| (936 | ) |
|
| (1,502 | ) |
Acquisitions of property and equipment |
|
| — |
|
|
| (5 | ) |
|
| (5 | ) |
|
| (28 | ) |
Debt activity, net |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (162 | ) |
Repurchases of common stock |
|
| — |
|
|
| (561 | ) |
|
| (38 | ) |
|
| (1,746 | ) |
Common stock dividends |
|
| (43 | ) |
|
| (35 | ) |
|
| (119 | ) |
|
| (106 | ) |
Contributions from noncontrolling interests |
|
| 1 |
|
|
| — |
|
|
| 12 |
|
|
| — |
|
Distributions to noncontrolling interests |
|
| (4 | ) |
|
| — |
|
|
| (10 | ) |
|
| — |
|
Other |
|
| — |
|
|
| (1 | ) |
|
| (17 | ) |
|
| (23 | ) |
Net change in cash, cash equivalents and restricted cash from discontinued operations |
|
| 50 |
|
|
| (1,673 | ) |
|
| 31 |
|
|
| 966 |
|
Net change in cash, cash equivalents and restricted cash |
| $ | 228 |
|
| $ | (2,197 | ) |
| $ | 53 |
|
| $ | (790 | ) |
Cash, cash equivalents and restricted cash at end of period |
| $ | 1,897 |
|
| $ | 1,656 |
|
| $ | 1,897 |
|
| $ | 1,656 |
|
Operating Cash Flow
Net
Despite our portfolio enhancements, aggressive cost reductions and operational advancements, our financial results continue to be challenged by commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. As presented in the table above, net cash provided by operating activities increased 96% primarily duecontinued to significantly higher commodity prices as compared to the first nine monthsbe a significant source of 2016.
Our consolidated operatingcapital and liquidity. Operating cash flow funded 100% ofall our capital expenditures and dividends during the firstthree months and nine months of 2017. In 2016, leveraging our liquidity, we also used cash balances and proceeds from our common stock offering and non-core asset divestitures to fund our acquisitions and capital expenditures.ended September 30, 2020.
Divestitures of PropertyOperating Cash Flow
Despite our portfolio enhancements, aggressive cost reductions and Equipment
During the first nine months of 2017, as part ofoperational advancements, 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 Stock
In February 2016, we issued 79 million shares of our common stockfinancial results continue to the public, inclusive of 10 million shares sold as partbe challenged by commodity prices and deterioration of the underwriters’ option. Net proceedsmacro-economic environment resulting from the offering were approximately $1.5 billion.
Proceeds from Sale of Investment
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 2016 acquisition further discussed in Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
37
Capital Expenditures and Acquisitions of Property, Equipment and Businesses
The amountsunprecedented COVID-19 pandemic. As presented in the table below reflectabove, net cash payments forprovided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow funded all our capital expenditures including cash paid for capital expenditures incurred in prior periods.
|
| 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 |
|
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, Net
During 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.
38
Shareholder and Noncontrolling Interests Distributions
The following table summarizes our common stock dividends during the firstthree months and nine months of 2017 and 2016. In the second quarter of 2016, we decreased our quarterly cash dividend rate to $0.06 per share.
| 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 |
|
|
|
|
|
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 Distributions
Devon received $199 million in distributions from EnLink and the General Partner during the first nine months of 2017 and 2016.
Issuance of Subsidiary Units
During 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. Inended September 2017, EnLink issued preferred units in an underwritten public offering generating net proceeds of approximately $394 million.30, 2020.
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.
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 and other contractual commitments as discussed in this section.
Operating Cash Flow
Despite our portfolio enhancements, aggressive cost reductions and operational advancements, our financial results continue to be challenged by commodity prices and deterioration of the macro-economic environment resulting from the unprecedented COVID-19 pandemic. As presented in the table above, net cash provided by operating activities continued to be a significant source of capital and liquidity. Operating cash flow funded all our capital expenditures and dividends during the three months and nine months ended September 30, 2020.
Divestitures of Property and Equipment
During the first nine months of 2019, we sold non-core U.S. assets for approximately $347 million, net of customary purchase price adjustments. For additional information, please see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
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.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Delaware Basin |
| $ | 147 |
|
| $ | 263 |
|
| $ | 560 |
|
| $ | 733 |
|
Powder River Basin |
|
| 24 |
|
|
| 98 |
|
|
| 155 |
|
|
| 214 |
|
Eagle Ford |
|
| 17 |
|
|
| 39 |
|
|
| 153 |
|
|
| 147 |
|
Anadarko Basin |
|
| 2 |
|
|
| 88 |
|
|
| 20 |
|
|
| 325 |
|
Other |
|
| 3 |
|
|
| 7 |
|
|
| 9 |
|
|
| 26 |
|
Total oil and gas |
|
| 193 |
|
|
| 495 |
|
|
| 897 |
|
|
| 1,445 |
|
Midstream |
|
| 7 |
|
|
| 27 |
|
|
| 26 |
|
|
| 38 |
|
Other |
|
| 4 |
|
|
| 4 |
|
|
| 13 |
|
|
| 19 |
|
Total capital expenditures |
| $ | 204 |
|
| $ | 526 |
|
| $ | 936 |
|
| $ | 1,502 |
|
Acquisitions |
| $ | — |
|
| $ | 5 |
|
| $ | 5 |
|
| $ | 28 |
|
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and other corporate activities. Our capital program is designed to operate within or near operating cash flow. This is
37
evidenced by our operating cash flow funding all of our capital expenditures for the three months and nine months ended September 30, 2020. Our capital investment program is driven by a disciplined allocation process focused on returns. Our capital expenditures are lower in 2020 primarily due to decreased spending across the majority of our assets. In response to the current macro-economic environment, we reduced our 2020 capital expenditures outlook by approximately $800 million, or 45% compared to the original capital budget.
Debt Activity
During the first nine months of 2019, our debt decreased $162 million due to the repayment of our 6.30% senior notes at maturity.
Shareholder Distributions and Stock Activity
The following table summarizes our common stock dividends during the first nine months of 2020 and 2019. Beginning with the second quarter of 2020, we increased our quarterly dividend 22%, to $0.11 per share. We previously increased our quarterly dividend to $0.09 per share commencing with the second quarter of 2019.
| Amounts |
|
| Rate Per Share |
| ||
Quarter Ended 2020: |
|
|
|
|
|
|
|
First quarter | $ | 34 |
|
| $ | 0.09 |
|
Second quarter |
| 42 |
|
| $ | 0.11 |
|
Third quarter |
| 43 |
|
| $ | 0.11 |
|
Total year-to-date | $ | 119 |
|
|
|
|
|
Quarter Ended 2019: |
|
|
|
|
|
|
|
First quarter | $ | 34 |
|
| $ | 0.08 |
|
Second quarter |
| 37 |
|
| $ | 0.09 |
|
Third quarter |
| 35 |
|
| $ | 0.09 |
|
Total year-to-date | $ | 106 |
|
|
|
|
|
We repurchased 2.2 million shares of common stock for $38 million in the first nine months of 2020 and 64.2 million shares of common stock for $1.7 billion in the first nine months of 2019 under share repurchase programs authorized by our Board of Directors. For additional information, see Note 16in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Noncontrolling Interest Contributions and Distributions
During the first nine months of 2020, we received $12 million in contributions from our noncontrolling interests in CDM and distributed $10 million to our noncontrolling interests in CDM.
38
Cash Flows from Discontinued Operations
All cash flows in the following table relate to activities of our Canadian business that Devon sold in June 2019 and the Barnett Shale assets that Devon sold on October 1, 2020.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Canadian tax payments |
| $ | — |
|
| $ | — |
|
| $ | (173 | ) |
| $ | — |
|
Settlements of intercompany foreign denominated assets/liabilities |
|
| — |
|
|
| (1 | ) |
|
| — |
|
|
| (32 | ) |
Other |
|
| 45 |
|
|
| (93 | ) |
|
| 44 |
|
|
| 69 |
|
Operating activities |
|
| 45 |
|
|
| (94 | ) |
|
| (129 | ) |
|
| 37 |
|
Divestitures of property and equipment - Canadian operations |
|
| 2 |
|
|
| 7 |
|
|
| 2 |
|
|
| 2,608 |
|
Divestitures of property and equipment - Barnett Shale assets |
|
| — |
|
|
| (1 | ) |
|
| 170 |
|
|
| — |
|
Capital expenditures and other |
|
| (1 | ) |
|
| (11 | ) |
|
| (1 | ) |
|
| (136 | ) |
Investing activities |
|
| 1 |
|
|
| (5 | ) |
|
| 171 |
|
|
| 2,472 |
|
Debt activity, net |
|
| — |
|
|
| (1,552 | ) |
|
| — |
|
|
| (1,552 | ) |
Other |
|
| — |
|
|
| (19 | ) |
|
| — |
|
|
| (27 | ) |
Financing activities |
|
| — |
|
|
| (1,571 | ) |
|
| — |
|
|
| (1,579 | ) |
Settlements of intercompany foreign denominated assets/liabilities |
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 32 |
|
Other |
|
| 4 |
|
|
| (4 | ) |
|
| (11 | ) |
|
| 4 |
|
Effect of exchange rate changes on cash |
|
| 4 |
|
|
| (3 | ) |
|
| (11 | ) |
|
| 36 |
|
Net change in cash, cash equivalents and restricted cash of discontinued operations |
| $ | 50 |
|
| $ | (1,673 | ) |
| $ | 31 |
|
| $ | 966 |
|
Operating cash flows during the first nine months of 2020 include $173 million of cash income and withholding tax payments in Canada related to divestitures and was also negatively impacted by lower commodity prices. Foreign currency denominated intercompany loan activity resulted in a realized loss of $32 million during the first nine months of 2019 as a result of the strengthening of the U.S. dollar in relation to the Canadian dollar. There was an offset in the effect of exchange rate changes on cash line in the table above, resulting in no impact to the net change in cash, cash equivalents and restricted cash. Investing cash flows during the first nine months of 2020 include $170 million in deposit funds from BKV due to the amended terms on the sale of our Barnett Shale assets. On June 27, 2019, we completed the sale of our Canadian business for proceeds of $2.6 billion. See Note 2and Note 17 in “Part I. Financial Information – Item 1. Financial Statements” in this report for additional details on these divestitures.
Liquidity
The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil, natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire operations and properties from other operators or land owners to enhance our existing portfolio of assets.
Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on hand and asset divestiture proceeds. 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. If needed, we can also issue debt and equity securities, including through transactions under our shelf registration statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to fund our planned capital requirements as discussed in this section.
Beginning in the first quarter of 2020, the macro-economic environment deteriorated significantly and has created extreme volatility primarily due to concerns arising from the COVID-19 pandemic. In response to this environment, we will continue to maintain flexibility within our capital program as we continue to focus on protecting our financial strength and maintaining operational continuity. Additionally, we have initiatives underway to reduce annualized production, administrative and financing expenses by a total of $300 million.
39
Operating Cash Flow
Key inputs into determining our planned capital investment are the amounts of cash we hold and operating cash flow we expect to generate over the next one to three or more years. At the end of the third quarter of 2020, we held approximately $1.9 billion of cash, inclusive of $190 million of cash restricted for discontinued operations. Our operating cash flow isforecasts are sensitive to many variables and include a measure of uncertainty as the actual results of these variables may differ from our expectations.
Commodity Prices – The most uncertain and volatile of whichvariables for our operating cash flow are the prices of the oil, bitumen, gas and NGLs we produce and sell. Our consolidated operating cash flow increased approximately $1.2 billionPrices are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in the first nine months of 2017 compared to the first nine months of 2016 largely due to increases in commodity prices. We expect operating cash flow to continue to be a key source of liquidity as we adjustprices and are beyond our capital program to invest within our operating cash flow. Furthermore, proceeds from non-core asset divestitures will provide additional liquidity as needed.control.
39
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% ofhedge 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 onWe currently have approximately 30% of our 2021 oil production hedged with an average floor price of $38/Bbl and approximately 33% of our 2021 gas production hedged with an average floor price of $2.45/Mcf. We are continuing to build our 2021 and 2022 hedge positions at market prices. The key terms to our oil, gas and NGL derivative positions in place atfinancial instruments as of September 30, 2017, see 2020 are presented in Note 3 in “Part I. Financial Information – Item 1. Financial Statements” inof this report.
Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is also generally true during periods of rising commodity prices.
Driven by lower realized prices, margins and capital investment, we have begun initiatives to reduce our annualized production and administrative expenses a total of $225 million. We expect these annualized savings to be sustainable as we tailor our workforce and operations for current activity levels.
Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate and counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or collateral postings and other protections allowed per our agreements.
Divestitures of Property and Equipment and Special Dividend
In May 2017, we announced a program to divest approximately $1 billion of upstream assets. These non-core assets identified for monetization include select portions of the
We closed on our 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 totalingon October 1, 2020, receiving proceeds of approximately $400$490 million, beforenet of purchase price adjustments. The most significant asset remainingadjustments, including a $170 million deposit received in this program is select Barnett Shale leasehold. Data roomsthe second quarter of 2020.
Our Board of Directors approved a $0.26 per share special dividend for approximately $100 million in the Barnett properties opened in September 2017aggregate that was paid on October 1, 2020.
Capital Expenditures
In response to the current macro-economic environment, we reduced our 2020 capital expenditures outlook by approximately $800 million, or 45% compared to the original capital budget. Our exploration and initial bids are expected duringdevelopment budget for the fourth quarter of 2017.
Capital Expenditures
Excluding EnLink, our 2017 capital expenditures are2020 is expected to range from $2.4$160 million to $200 million. As economic factors change, we will continue to be flexible with our capital program.
Debt Repurchases
Our Board of Directors has authorized a $1.5 billion debt repurchase program. Repurchases will be dependent on market conditions and may be made through open market purchases, tender offers or other transaction structures. The repurchases are expected 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 monthsgenerate $75 million of 2017 and are forecasted to range from $0.7 billion to $0.8 billion in the fourth quarterannualized financing cost savings.
40
Credit Availability
We have a $3.0 billion Senior Credit Facility. As of September 30, 2017,2020, we had approximately $2.9$3.0 billion of available borrowing capacity under this facility, net of $59 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant.our Senior Credit Facility. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At September 30, 2017,2020, there were no borrowings under our commercial paper program.
EnLink Liquidity
EnLink 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, thereprogram, and we were $9 million in outstanding letters of credit and no outstanding borrowings undercompliance with 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.Senior Credit Facility’s financial covenant.
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 BBBBBB- with a stable outlook. In March 2017,Our credit rating from Fitch Ratings affirmed our BBB+is BBB with a positive 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.
There are no “rating triggers”Strategic Merger of Equals
On September 26, 2020, Devon and WPX entered into the Merger Agreement to combine in anyan all-stock merger of equals transaction expected to close in the first quarter of 2021. The strategic combination accelerates our or EnLink’s contractual debt obligations that would accelerate scheduled maturities shouldtransition to a debt rating fall belowcash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash to shareholders. Effective upon the closing of the Merger, Devon intends to implement a specified level. However, these downgradesfixed plus variable dividend strategy. In addition to maintaining its fixed quarterly dividend, the future variable dividends could adversely impact our and EnLink’s interest ratebe up to 50% of excess quarterly free cash flow, subject to certain criteria being met. Excess free cash flow for purposes of computing the variable dividend is based on any credit facility borrowingsthe net cash from operating activities less capital expenditures and the abilityfixed quarterly cash dividend. The Merger is also expected to economically access debt markets in the future.
40
create value from operational and corporate synergies and reduced financing costs.
Critical Accounting Estimates
Income Taxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal, state, provincial and foreign 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 losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. At September 30, 2017,Due to an unprecedented downturn in the commodity price environment and the resulting asset impairments, Devon had significant deferred tax assets at March 31, 2020. Accordingly, we continued to havereassessed the realizability of our deferred tax assets in future periods and recorded a 100% valuation allowance against the U.S.our net deferred tax assets that largely resulted from prior year cumulative financial losses primarily due toduring the first quarter of 2020.As of September 30, 2020, we remain in a full cost impairments. Further, we continue to record a partial valuation allowance against certain Canadian deferred taxposition.
Valuation of Long-Lived Assets
Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level (“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
The accrualsManagement evaluates assets for deferred taximpairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, and liabilities are oftenthe fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. The expected future cash flows used for impairment reviews include future production volumes associated with proved producing and risk-adjusted proved undeveloped, probable and possible reserves.
41
Besides the risk-adjusted estimates of reserves and future production volumes, future commodity prices are the largest driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we historically have utilized NYMEX forward strip prices for the first five years and applied internally generated price forecasts for subsequent years. In response to the COVID-19 pandemic, the NYMEX forward market became highly illiquid as evidenced by materially reduced trading volumes for periods beyond 2021. Therefore, we altered our price forecast assumptions to perform our March 31, 2020 impairment computations. Specifically, we supplemented the NYMEX forward strip prices with price forecasts published by reputable investment banks and reservoir engineering firms to estimate our future revenues as of March 31, 2020.
We also estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost movements to price movements similar to recent history. To measure indicated impairments, we use a market-based weighted-average cost of capital to discount the future net cash flows. Changes to any of the reserves or market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.
Reduced demand from the COVID-19 pandemic and management of production levels from OPEC caused WTI pricing to decrease more than 60% during the first quarter of 2020. As a result, we reduced our planned 2020 capital investment 45%. With materially lower commodity prices and reduced near-term investment, we assessed all our oil and gas fields for impairment as of March 31, 2020 and recognized proved and unproved impairments totaling $2.8 billion. The impairments relate to our Anadarko Basin and Rockies fields in which our basis included acquisitions completed in 2016 and 2015, respectively, when commodity prices were much higher than they are today.
We assessed our Eagle Ford asset for impairment as of June 30, 2020 and September 30, 2020 utilizing the same methodology we applied for the impairment assessments for all of our and oil and gas fields in the first quarter of 2020. Our Eagle Ford asset’s sum of undiscounted cash flows exceeded the carrying value indicating no impairment as of September 30, 2020. Further, as a result of improved oil pricing, the cushion increased significantly from March 31, 2020 to September 30, 2020. If prices significantly deteriorate and/or management lowers the planned capital investment in the Eagle Ford field, our Eagle Ford asset could be subject to a material impairment of capitalized costs.
Goodwill
We test goodwill for impairment annually at October 31, or more frequently if events or changes in circumstances dictate that the carrying value of goodwill may not be recoverable. We perform a qualitative assessment to determine whether it is more likely than not that the fair value of goodwill is less than its carrying amount. As part of our qualitative assessment, we considered the general macro-economic, industry and market conditions, changes in cost factors, actual and expected financial performance, significant changes in management, strategy or customers and stock performance. If the qualitative assessment determines that a quantitative goodwill impairment test is required, then the fair value is compared to the carrying value. If the fair value is less than the carrying value, an impairment charge will be recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are not available, the fair value is estimated based upon a valuation analyses including comparable companies and transactions and premiums paid.
Because the trading price of judgment by management. These assumptions and judgments are reviewed and adjustedour common stock decreased 73% during the first quarter of 2020 in response to the COVID-19 pandemic, we performed a goodwill impairment test as facts and circumstances change. Material changes toof March 31, 2020. While the cushion narrowed significantly since our income tax accruals may occurlast impairment evaluation, we concluded an impairment was not required as of March 31, 2020. The two most critical judgements included in the futureMarch 31, 2020, test were the period utilized to determine Devon’s market capitalization and the control premium. For the test performed as of March 31, 2020 we derived our market capitalization by using our average common stock price from the latter two thirds of March 2020, to align with the time in the quarter subsequent to a key OPEC+ meeting and the date COVID-19 was officially classified as a pandemic. We applied a control premium based on recent comparable market transactions.
Subsequent to the progressend of ongoing audits, changesthe first quarter of 2020, Devon’s common stock price increased approximately 37% during the second and third quarter but remains significantly less than our average trading price before the events experienced in legislationthe first quarter of 2020. Although our common stock price and commodity prices are in a period of high volatility, a sustained period of depressed commodity prices would adversely affect our estimates of future operating results, which could result in future goodwill impairments due to the potential impact on the cash flows of our operations. The impairment of goodwill has no effect on liquidity or resolutioncapital resources. However, it would adversely affect our results of other pending matters.operations in the period recognized.
For additional information regarding our critical accounting policies and estimates, see our 2019 Annual Report on Form 10-K.
42
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 20172020 Results” in this Item 2.2 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. For more information on the results of discontinued operations for our Barnett Shale asset and Canadian operations, see Note 17 in “Part I. Financial Information – Item 1. Financial Statements” in this report. 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 derivatives and financial instrument fair values and foreign currency, gains and losses on asset sales, dispositions, noncash asset impairments gains(including noncash unproved asset impairments), deferred tax asset valuation allowance, costs 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 tofair value changes in derivatives andderivative financial instrument fair valuesinstruments and foreign currency, noncash asset impairments (including an impairment of goodwill),changes in tax legislation and restructuring and transaction costs gains on asset sales, costs associated with the early retirement of debt and deferred tax asset valuation allowance. workforce reductions described further in Note 6.
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.
4143
Below are reconciliations of our core earnings (loss) and core earnings (loss) per share attributable to Devon to their comparable GAAP measures.
|
| 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 | ) |
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||||||||||
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
|
| Before tax |
|
| After tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| ||||||||
2020 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (193 | ) |
| $ | (103 | ) |
| $ | (105 | ) |
| $ | (0.29 | ) |
| $ | (2,980 | ) |
| $ | (2,470 | ) |
| $ | (2,475 | ) |
| $ | (6.58 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset and exploration impairments |
| 36 |
|
|
| 29 |
|
|
| 29 |
|
|
| 0.08 |
|
|
| 2,816 |
|
|
| 2,178 |
|
|
| 2,178 |
|
|
| 5.80 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (5 | ) |
|
| (5 | ) |
|
| (0.01 | ) |
|
| — |
|
|
| 252 |
|
|
| 252 |
|
|
| 0.65 |
|
Fair value changes in financial instruments |
| 97 |
|
|
| 74 |
|
|
| 74 |
|
|
| 0.19 |
|
|
| 71 |
|
|
| 55 |
|
|
| 55 |
|
|
| 0.14 |
|
Change in tax legislation |
| — |
|
|
| (43 | ) |
|
| (43 | ) |
|
| (0.11 | ) |
|
| — |
|
|
| (105 | ) |
|
| (105 | ) |
|
| (0.27 | ) |
Restructuring and transaction costs |
| 32 |
|
|
| 25 |
|
|
| 25 |
|
|
| 0.07 |
|
|
| 32 |
|
|
| 25 |
|
|
| 25 |
|
|
| 0.06 |
|
Core loss attributable to Devon (Non-GAAP) | $ | (28 | ) |
| $ | (23 | ) |
| $ | (25 | ) |
| $ | (0.07 | ) |
| $ | (61 | ) |
| $ | (65 | ) |
| $ | (70 | ) |
| $ | (0.20 | ) |
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) attributable to Devon (GAAP) | $ | (2 | ) |
| $ | 13 |
|
| $ | 13 |
|
| $ | 0.04 |
|
| $ | (150 | ) |
| $ | (103 | ) |
| $ | (103 | ) |
| $ | (0.27 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| (0.00 | ) |
Asset impairments |
| 3 |
|
|
| 3 |
|
|
| 3 |
|
|
| 0.00 |
|
|
| 182 |
|
|
| 143 |
|
|
| 143 |
|
|
| 0.37 |
|
Fair value changes in foreign currency and other |
| (2 | ) |
|
| (3 | ) |
|
| (3 | ) |
|
| (0.01 | ) |
|
| 4 |
|
|
| 2 |
|
|
| 2 |
|
|
| 0.01 |
|
Core earnings (loss) attributable to Devon (Non-GAAP) | $ | (1 | ) |
| $ | 13 |
|
| $ | 13 |
|
| $ | 0.03 |
|
| $ | 34 |
|
| $ | 41 |
|
| $ | 41 |
|
| $ | 0.11 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss attributable to Devon (GAAP) | $ | (195 | ) |
| $ | (90 | ) |
| $ | (92 | ) |
| $ | (0.25 | ) |
| $ | (3,130 | ) |
| $ | (2,573 | ) |
| $ | (2,578 | ) |
| $ | (6.85 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| 165 |
|
|
| 80 |
|
|
| 80 |
|
|
| 0.22 |
|
|
| 2,919 |
|
|
| 2,405 |
|
|
| 2,405 |
|
|
| 6.38 |
|
Discontinued Operations |
| 1 |
|
|
| — |
|
|
| — |
|
|
| (0.01 | ) |
|
| 184 |
|
|
| 144 |
|
|
| 144 |
|
|
| 0.38 |
|
Core loss attributable to Devon (Non-GAAP) | $ | (29 | ) |
| $ | (10 | ) |
| $ | (12 | ) |
| $ | (0.04 | ) |
| $ | (27 | ) |
| $ | (24 | ) |
| $ | (29 | ) |
| $ | (0.09 | ) |
2019 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) attributable to Devon (GAAP) | $ | 190 |
|
| $ | 136 |
|
| $ | 136 |
|
| $ | 0.34 |
|
| $ | (88 | ) |
| $ | (91 | ) |
| $ | (91 | ) |
| $ | (0.22 | ) |
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (1 | ) |
|
| (1 | ) |
|
| (1 | ) |
|
| (0.00 | ) |
|
| (48 | ) |
|
| (37 | ) |
|
| (37 | ) |
|
| (0.09 | ) |
Asset and exploration impairments |
| 14 |
|
|
| 11 |
|
|
| 11 |
|
|
| 0.03 |
|
|
| 16 |
|
|
| 13 |
|
|
| 13 |
|
|
| 0.03 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| 4 |
|
|
| 4 |
|
|
| 0.01 |
|
|
| — |
|
|
| 2 |
|
|
| 2 |
|
|
| 0.00 |
|
Fair value changes in financial instruments |
| (57 | ) |
|
| (44 | ) |
|
| (44 | ) |
|
| (0.11 | ) |
|
| 465 |
|
|
| 358 |
|
|
| 358 |
|
|
| 0.86 |
|
Restructuring and transaction costs |
| 10 |
|
|
| 8 |
|
|
| 8 |
|
|
| 0.02 |
|
|
| 73 |
|
|
| 57 |
|
|
| 57 |
|
|
| 0.14 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 156 |
|
| $ | 114 |
|
| $ | 114 |
|
| $ | 0.29 |
|
| $ | 418 |
|
| $ | 302 |
|
| $ | 302 |
|
| $ | 0.72 |
|
Discontinued Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) attributable to Devon (GAAP) | $ | (39 | ) |
| $ | (27 | ) |
| $ | (27 | ) |
| $ | (0.07 | ) |
| $ | 93 |
|
| $ | 378 |
|
| $ | 378 |
|
| $ | 0.91 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset dispositions |
| (35 | ) |
|
| (20 | ) |
|
| (20 | ) |
|
| (0.05 | ) |
|
| (222 | ) |
|
| (479 | ) |
|
| (479 | ) |
|
| (1.16 | ) |
Asset and exploration impairments |
| — |
|
|
| — |
|
|
| — |
|
|
| 0.00 |
|
|
| 37 |
|
|
| 27 |
|
|
| 27 |
|
|
| 0.07 |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (4 | ) |
|
| (4 | ) |
|
| (0.01 | ) |
|
| — |
|
|
| 23 |
|
|
| 23 |
|
|
| 0.05 |
|
Early retirement of debt |
| 58 |
|
|
| 45 |
|
|
| 45 |
|
|
| 0.11 |
|
|
| 58 |
|
|
| 45 |
|
|
| 45 |
|
|
| 0.11 |
|
Fair value changes in financial instruments and foreign currency and other |
| (6 | ) |
|
| (9 | ) |
|
| (9 | ) |
|
| (0.02 | ) |
|
| (29 | ) |
|
| (32 | ) |
|
| (32 | ) |
|
| (0.08 | ) |
Restructuring and transaction costs |
| 5 |
|
|
| 4 |
|
|
| 4 |
|
|
| 0.01 |
|
|
| 244 |
|
|
| 178 |
|
|
| 178 |
|
|
| 0.44 |
|
Core earnings (loss) attributable to Devon (Non-GAAP) | $ | (17 | ) |
| $ | (11 | ) |
| $ | (11 | ) |
| $ | (0.03 | ) |
| $ | 181 |
|
| $ | 140 |
|
| $ | 140 |
|
| $ | 0.34 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings attributable to Devon (GAAP) | $ | 151 |
|
| $ | 109 |
|
| $ | 109 |
|
| $ | 0.27 |
|
| $ | 5 |
|
| $ | 287 |
|
| $ | 287 |
|
| $ | 0.69 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations |
| (34 | ) |
|
| (22 | ) |
|
| (22 | ) |
|
| (0.05 | ) |
|
| 506 |
|
|
| 393 |
|
|
| 393 |
|
|
| 0.94 |
|
Discontinued Operations |
| 22 |
|
|
| 16 |
|
|
| 16 |
|
|
| 0.04 |
|
|
| 88 |
|
|
| (238 | ) |
|
| (238 | ) |
|
| (0.57 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 139 |
|
| $ | 103 |
|
| $ | 103 |
|
| $ | 0.26 |
|
| $ | 599 |
|
| $ | 442 |
|
| $ | 442 |
|
| $ | 1.06 |
|
44
EBITDAX and Field-Level Cash Margin
To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as oil, gas and NGL sales less production expenses. Production expenses consist of lease operating, gathering, processing and transportation expenses, as well as production and property taxes.
We exclude financing costs from EBITDAX to assess our operating results without regard to our financing methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating performance.
We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net earnings from continuing operations.
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
| 2020 |
|
| 2019 |
|
| 2020 |
|
| 2019 |
| ||||
Net earnings (loss) (GAAP) | $ | (90 | ) |
| $ | 109 |
|
| $ | (2,573 | ) |
| $ | 287 |
|
Net (earnings) loss from discontinued operations, net of tax |
| (13 | ) |
|
| 27 |
|
|
| 103 |
|
|
| (378 | ) |
Financing costs, net |
| 66 |
|
|
| 60 |
|
|
| 200 |
|
|
| 186 |
|
Income tax expense (benefit) |
| (90 | ) |
|
| 54 |
|
|
| (510 | ) |
|
| 3 |
|
Exploration expenses |
| 39 |
|
|
| 18 |
|
|
| 163 |
|
|
| 29 |
|
Depreciation, depletion and amortization |
| 299 |
|
|
| 381 |
|
|
| 999 |
|
|
| 1,115 |
|
Asset impairments |
| — |
|
|
| — |
|
|
| 2,666 |
|
|
| — |
|
Asset dispositions |
| — |
|
|
| (1 | ) |
|
| — |
|
|
| (48 | ) |
Share-based compensation |
| 19 |
|
|
| 20 |
|
|
| 58 |
|
|
| 64 |
|
Derivative and financial instrument non-cash valuation changes |
| 97 |
|
|
| (57 | ) |
|
| 71 |
|
|
| 464 |
|
Restructuring and transaction costs |
| 32 |
|
|
| 10 |
|
|
| 32 |
|
|
| 73 |
|
Accretion on discounted liabilities and other |
| — |
|
|
| 5 |
|
|
| (35 | ) |
|
| (10 | ) |
EBITDAX (non-GAAP) |
| 359 |
|
|
| 626 |
|
|
| 1,174 |
|
|
| 1,785 |
|
Marketing and midstream revenues and expenses, net |
| 2 |
|
|
| (16 | ) |
|
| 28 |
|
|
| (48 | ) |
Commodity derivative cash settlements |
| (10 | ) |
|
| (71 | ) |
|
| (343 | ) |
|
| (128 | ) |
General and administrative expenses, cash-based |
| 56 |
|
|
| 87 |
|
|
| 198 |
|
|
| 292 |
|
Field-level cash margin (non-GAAP) | $ | 407 |
|
| $ | 626 |
|
| $ | 1,057 |
|
| $ | 1,901 |
|
4245
Item 3. Quantitative and QualitativeQualitative Disclosures About Market Risk
Commodity Price Risk
As of September 30, 2017,2020, we have commodity derivatives that pertain to a portion of our estimated production for the last three months of 2017,2020, as well as 2018for 2021 and 2019.2022. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3in “Part I. Financial Information – Item 1. Financial Statements” in this report.
The fair values of our commodity derivatives are largely determined by the forward curves of the relevant price indices. At September 30, 2017,2020, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $170$131 million.
Interest Rate Risk
As of September 30, 2017,2020, we had total debt of $10.4$4.3 billion. Of this amount, $10.3 billion bearsAll of our debt is based on fixed interest rates averaging 5.3%, and $74 million is comprised of floating rate debt with interest rates averaging 3.2%6.0%.
As of September 30, 2017, we had open interest rate swap positions that are presented in Note 3 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.
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 ourWe had no material foreign currency risk at September 30, 2017 balance sheet.2020.
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 September 30, 20172020 to ensure that the information required to be disclosed by Devon in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
4346
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 20162019 Annual Report on Form 10-K and other SEC filings for additional information regarding certain environmental matters involving the Company.information.
ThereExcept for the addition of the risks related to the Merger discussed below and the pandemic risk factor discussed in our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020, there have been no material changes to the information included in Item 1A. “Risk Factors” in our 20162019 Annual Report on Form 10-K.10-K.
Risks Relating to the Merger
We may fail to realize the anticipated benefits of the Merger, and any failure to successfully integrate the businesses and operations of Devon and WPX may adversely affect our future results.
The success of the Merger will depend on, among other things, the combined company’s ability to combine the Devon and WPX businesses in a manner that realizes anticipated synergies and benefits. If the combined company is not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected.
We and WPX have operated and, until the completion of the Merger, will continue to operate independently. There can be no assurances that our businesses can be integrated successfully. It is possible that the integration process could result in the loss of key Devon employees or key WPX employees, the loss of customers, the disruption of our or WPX’s ongoing businesses, inconsistencies in standards, controls, procedures and policies, unexpected integration issues, higher than expected integration costs and an overall post‑completion integration process that takes longer than originally anticipated. Furthermore, the combined company’s board of directors and management team will consist of directors and employees from each of Devon and WPX, as applicable. Combining the boards of directors and management teams of each company into a single board and a single management team could require the reconciliation of differing priorities and strategic philosophies, which may not be successful or take longer than anticipated.
We are subject to certain restrictions in the Merger Agreement that may hinder operations pending the consummation of the Merger, and we may be the target of securities class action and derivative lawsuits as a result of the Merger.
Whether or not the Merger is completed, the pending Merger may disrupt our current plans and operations, which could have an adverse effect on our business operations and financial results. During the pendency of the Merger, the Merger Agreement generally requires us to operate our business in all material respects in the ordinary course and not to engage in specified types of actions during this period, in each case subject to certain exceptions. These restrictions could be in place for an extended period of time if the consummation of the Merger is delayed, which may delay or prevent us from undertaking business opportunities that, absent the Merger Agreement, we might have pursued, or effectively respond to competitive pressures or industry developments.
In addition, litigation is common in connection with mergers and acquisitions of public companies, regardless of any merits related to the claims. Defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages. Moreover, if a plaintiff is successful in obtaining an injunction prohibiting completion of the Merger, the injunction may delay or prevent the Merger from being completed, which may adversely affect our business, results of operations and financial condition.
The Merger Agreement could be terminated, which could negatively impact us.
The Merger is subject to a number of conditions that must be satisfied or waived (to the extent permissible) prior to the completion of the Merger. These conditions to the completion of the Merger, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all, and, accordingly, the Merger may be delayed or not completed. The Merger Agreement also contains certain termination rights for both Devon and WPX, including if the Merger is not consummated by March 26, 2021, and further provides that, upon termination of the Merger Agreement under certain circumstances, we may be required to pay WPX a termination fee equal to $75 million.
If the Merger is not completed, our ongoing business may be adversely affected and, without realizing any of the benefits of having completed the Merger, we may experience certain negative effects, including the following: (i) may experience negative
47
reactions from the financial markets and business partners; (ii) we will still be required to pay certain significant costs relating to the Merger, such as legal, accounting and other advisory fees and printing costs; and (iii) matters relating to the Merger (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could have been beneficial to us.
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 third quarter of 2017.
2020 (shares in thousands).
Period |
| Total Number of Shares Purchased (1) |
|
| Average Price Paid per Share |
|
| Total Number of Shares Purchased (1) |
|
| Average Price Paid per Share |
|
| Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs (2) |
|
| Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
| ||||||
July 1 - July 31 |
|
| 48,112 |
|
| $ | 32.08 |
|
|
| 5 |
|
| $ | 10.80 |
|
|
| — |
|
| $ | 962 |
|
August 1 - August 31 |
|
| 16,504 |
|
| $ | 31.69 |
|
|
| 1 |
|
| $ | 12.64 |
|
|
| — |
|
| $ | 962 |
|
September 1 - September 30 |
|
| 1,108 |
|
| $ | 31.81 |
|
|
| 66 |
|
| $ | 9.43 |
|
|
| — |
|
| $ | 962 |
|
Total |
|
| 65,724 |
|
| $ | 31.97 |
|
|
| 72 |
|
| $ | 9.58 |
|
|
| — |
|
|
|
|
|
|
| These amounts reflect the shares received by us from employees for the payment of personal income tax withholding on vesting transactions. |
(2) | On December 17, 2019, we announced a $1.0 billion share repurchase program that has a December 31, 2020 expiration date. As of September 30, 2020, we had repurchased 2.2 million common shares for $38 million, or $16.85 per share, under our share repurchase program. Devon has temporarily suspended its share repurchase program. If Devon were to resume share repurchases under the program, such repurchases may be made in open-market or private transactions. For additional information, see Note 16 in “Part I. Financial Information – Item 1. Financial Statements” of this report. |
Under the Devon Plan, eligible employees may purchasemade purchases of shares of our common stock through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible employees purchased approximately 10,4004,500 shares of our common stock in the third quarter of 2017,2020, 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.
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 third quarter of 2017, there were approximately 4,200 shares purchased by Canadian employees.
Item 3. Defaults Upon Senior Securities
Not applicable.
Item 4. Mine Safety Disclosures
Not applicable.
Not applicable.
4448
Exhibit Number |
| Description | |
|
| ||
| Agreement and Plan of Merger, dated as of September 26, 2020, by and among Devon Energy Corporation, East Merger Sub, Inc. and WPX Energy, Inc. (incorporated by reference to Exhibit 2.1 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318). | ||
| |||
10.1 | Support Agreement, dated as of September 26, 2020, by and among Devon Energy Corporation and certain affiliates of EnCap Investments L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318). | ||
10.2* | Employment Letter Agreement, dated as of September 26, 2020, by and between Devon Energy Corporation and David A. Hager (incorporated by reference to Exhibit 10.2 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318). | ||
10.3* | Employment Letter Agreement, dated as of September 26, 2020, by and between Devon Energy Corporation and Richard E. Muncrief (incorporated by reference to Exhibit 10.3 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318). | ||
10.4* | Employment Letter Agreement, dated as of September 26, 2020, by and between Devon Energy Corporation and Clay M. Gaspar (incorporated by reference to Exhibit 10.4 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318). | ||
10.5* | Employment Letter Agreement, dated as of September 26, 2020, by and between Devon Energy Corporation and Dennis C. Cameron (incorporated by reference to Exhibit 10.5 to Registrant’s Form 8-K filed September 28, 2020; File No. 001-32318). | ||
31.1 | |||
|
| ||
31.2 | |||
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| ||
32.1 | |||
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| ||
32.2 | |||
|
| ||
101.INS | Inline XBRL Instance | ||
|
| ||
101.SCH | Inline XBRL Taxonomy Extension Schema Document. | ||
|
| ||
101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | ||
|
| ||
101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | ||
|
| ||
101.LAB | Inline XBRL Taxonomy Extension Labels Linkbase Document. | ||
|
| ||
101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | ||
104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
________________
* Indicates management contract or compensatory plan or arrangement.
4549
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.
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|
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| DEVON ENERGY CORPORATION |
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| ||
Date: |
|
|
| /s/ Jeremy D. Humphers |
|
|
|
| Jeremy D. Humphers |
|
|
|
| Senior Vice President and Chief Accounting Officer |
4650