UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
☑ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2017March 31, 2022
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) (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, 525.5April 20, 2022, 660.0 million shares of common stock were outstanding.
DEVON ENERGY CORPORATION
FORM 10-Q
Part I. Financial Information | |||
Item 1. | 6 | ||
Consolidated | 6 | ||
7 | |||
8 | |||
9 | |||
10 | |||
| 10 | ||
11 | |||
11 | |||
13 | |||
14 | |||
15 | |||
16 | |||
16 | |||
17 | |||
Note 10 – Supplemental Information to Statements of Cash Flows | 17 | ||
17 | |||
18 | |||
18 | |||
19 | |||
19 | |||
20 | |||
20 | |||
22 | |||
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
| |
| 23 | ||
25 | |||
33 | |||
36 | |||
36 | |||
Item 3. |
| ||
Item 4. |
| ||
Part II. Other Information | |||
Item 1. |
| ||
Item 1A. |
| ||
Item 2. |
| ||
Item 3. |
| ||
Item 4. |
| ||
Item 5. |
| ||
Item 6. |
| ||
|
2
DEFINITIONS
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 this 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.
“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”Catalyst” means Devon Canada Corporation Incentive Savings Plan.Catalyst Midstream Partners, LLC.
“CDM” means Cotton Draw Midstream, L.L.C.
“DD&A” means depreciation, depletion and amortization expenses.
“Devon Plan”ESG” means Devon Energy Corporation Incentive Savings Plan.environmental, social and governance.
“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.
“N/M” means not meaningful.
3
“NGL” or “NGLs” means natural gas liquids.
“NYMEX” means New York Mercantile Exchange.
“OPIS”OPEC” means Oil Price Information Service.Organization of the Petroleum Exporting Countries.
“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
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 and adversely from our expectations due to a number of factors, including, but not limited to:
the volatility of oil, gas and NGL prices;
risks relating to the COVID-19 pandemic or other future pandemics;
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 relating to governmental regulation, including with respect to environmental matters;
risks related to regulatory, social and market efforts to address climate change;
our ability to successfully complete mergers, acquisitions and divestitures;
the extent to which insurance covers any losses we may experience;
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;
cyberattacks targeting our systems and infrastructure; and
our ability to successfully complete mergers, acquisitions and divestitures;
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
Part I. Financial Information
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 March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
|
| (Unaudited) |
| |||||
Oil, gas and NGL sales |
| $ | 3,175 |
|
| $ | 1,757 |
|
Oil, gas and NGL derivatives |
|
| (683 | ) |
|
| (528 | ) |
Marketing and midstream revenues |
|
| 1,320 |
|
|
| 821 |
|
Total revenues |
|
| 3,812 |
|
|
| 2,050 |
|
Production expenses |
|
| 618 |
|
|
| 458 |
|
Exploration expenses |
|
| 2 |
|
|
| 3 |
|
Marketing and midstream expenses |
|
| 1,324 |
|
|
| 842 |
|
Depreciation, depletion and amortization |
|
| 489 |
|
|
| 467 |
|
Asset dispositions |
|
| (1 | ) |
|
| (32 | ) |
General and administrative expenses |
|
| 94 |
|
|
| 107 |
|
Financing costs, net |
|
| 85 |
|
|
| 77 |
|
Restructuring and transaction costs |
|
| 0 |
|
|
| 189 |
|
Other, net |
|
| (61 | ) |
|
| (29 | ) |
Total expenses |
|
| 2,550 |
|
|
| 2,082 |
|
Earnings (loss) before income taxes |
|
| 1,262 |
|
|
| (32 | ) |
Income tax expense (benefit) |
|
| 267 |
|
|
| (248 | ) |
Net earnings |
|
| 995 |
|
|
| 216 |
|
Net earnings attributable to noncontrolling interests |
|
| 6 |
|
|
| 3 |
|
Net earnings attributable to Devon |
| $ | 989 |
|
| $ | 213 |
|
Net earnings per share: |
|
|
|
|
|
| ||
Basic net earnings per share: |
| $ | 1.48 |
|
| $ | 0.33 |
|
Diluted net earnings per share: |
| $ | 1.48 |
|
| $ | 0.32 |
|
Comprehensive earnings: |
|
|
|
|
|
| ||
Net earnings |
| $ | 995 |
|
| $ | 216 |
|
Other comprehensive earnings, net of tax: |
|
|
|
|
|
| ||
Pension and postretirement plans |
|
| 1 |
|
|
| 23 |
|
Other comprehensive earnings, net of tax |
|
| 1 |
|
|
| 23 |
|
Comprehensive earnings: |
| $ | 996 |
|
| $ | 239 |
|
Comprehensive earnings attributable to noncontrolling interests |
|
| 6 |
|
|
| 3 |
|
Comprehensive earnings attributable to Devon |
| $ | 990 |
|
| $ | 236 |
|
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 March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
|
| (Unaudited) |
| |||||
Cash flows from operating activities: |
|
|
|
|
|
| ||
Net earnings |
| $ | 995 |
|
| $ | 216 |
|
Adjustments to reconcile net earnings to net cash from operating activities: |
|
|
|
|
|
| ||
Depreciation, depletion and amortization |
|
| 489 |
|
|
| 467 |
|
Leasehold impairments |
|
| 1 |
|
|
| 1 |
|
Amortization of liabilities |
|
| (6 | ) |
|
| (7 | ) |
Total losses on commodity derivatives |
|
| 683 |
|
|
| 528 |
|
Cash settlements on commodity derivatives |
|
| (344 | ) |
|
| (232 | ) |
Gains on asset dispositions |
|
| (1 | ) |
|
| (32 | ) |
Deferred income tax expense (benefit) |
|
| 164 |
|
|
| (243 | ) |
Share-based compensation |
|
| 20 |
|
|
| 41 |
|
Early retirement of debt |
|
| — |
|
|
| (20 | ) |
Other |
|
| (21 | ) |
|
| 0 |
|
Changes in assets and liabilities, net |
|
| (143 | ) |
|
| (127 | ) |
Net cash from operating activities |
|
| 1,837 |
|
|
| 592 |
|
Cash flows from investing activities: |
|
|
|
|
|
| ||
Capital expenditures |
|
| (537 | ) |
|
| (499 | ) |
Acquisitions of property and equipment |
|
| (1 | ) |
|
| 0 |
|
Divestitures of property and equipment |
|
| 26 |
|
|
| 15 |
|
WPX acquired cash |
|
| — |
|
|
| 344 |
|
Distributions from equity method investments |
|
| 8 |
|
|
| 10 |
|
Contributions to equity method investments |
|
| (22 | ) |
|
| 0 |
|
Net cash from investing activities |
|
| (526 | ) |
|
| (130 | ) |
Cash flows from financing activities: |
|
|
|
|
|
| ||
Repayments of long-term debt |
|
| — |
|
|
| (533 | ) |
Early retirement of debt |
|
| — |
|
|
| (27 | ) |
Repurchases of common stock |
|
| (211 | ) |
|
| 0 |
|
Dividends paid on common stock |
|
| (667 | ) |
|
| (203 | ) |
Distributions to noncontrolling interests |
|
| (8 | ) |
|
| (4 | ) |
Acquisition of noncontrolling interests |
|
| 0 |
|
|
| (24 | ) |
Shares exchanged for tax withholdings and other |
|
| (73 | ) |
|
| (33 | ) |
Net cash from financing activities |
|
| (959 | ) |
|
| (824 | ) |
Effect of exchange rate changes on cash |
|
| 2 |
|
|
| 3 |
|
Net change in cash, cash equivalents and restricted cash |
|
| 354 |
|
|
| (359 | ) |
Cash, cash equivalents and restricted cash at beginning of period |
|
| 2,271 |
|
|
| 2,237 |
|
Cash, cash equivalents and restricted cash at end of period |
| $ | 2,625 |
|
| $ | 1,878 |
|
|
|
|
|
|
|
| ||
Reconciliation of cash, cash equivalents and restricted cash: |
|
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 2,459 |
|
| $ | 1,683 |
|
Restricted cash |
|
| 166 |
|
|
| 195 |
|
Total cash, cash equivalents and restricted cash |
| $ | 2,625 |
|
| $ | 1,878 |
|
See accompanying notes to consolidated financial statements
7
DEVON ENERGY CORPORATION AND SUBSIDIARIES
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Unaudited) |
|
|
|
|
|
| March 31, 2022 |
|
| December 31, 2021 |
| |||
|
| (Millions, except share data) |
|
|
|
|
| |||||||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Current assets: |
|
|
|
|
|
|
|
|
|
|
|
|
| |||
Cash and cash equivalents |
| $ | 2,781 |
|
| $ | 1,959 |
| ||||||||
Cash, cash equivalents and restricted cash |
| $ | 2,625 |
|
| $ | 2,271 |
| ||||||||
Accounts receivable |
|
| 1,462 |
|
|
| 1,356 |
|
|
| 2,002 |
|
|
| 1,543 |
|
Assets held for sale |
|
| — |
|
|
| 193 |
| ||||||||
Other current assets |
|
| 379 |
|
|
| 264 |
|
|
| 346 |
|
|
| 435 |
|
Total current assets |
|
| 4,622 |
|
|
| 3,772 |
|
|
| 4,973 |
|
|
| 4,249 |
|
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 |
|
| 13,566 |
|
|
| 13,536 |
| ||||||||
Other property and equipment, net ($119 million and $111 million related to CDM in 2022 and 2021, respectively) |
|
| 1,508 |
|
|
| 1,472 |
| ||||||||
Total property and equipment, net |
|
| 15,074 |
|
|
| 15,008 |
| ||||||||
Goodwill |
|
| 3,964 |
|
|
| 3,964 |
|
|
| 753 |
|
|
| 753 |
|
Right-of-use assets |
|
| 229 |
|
|
| 235 |
| ||||||||
Investments |
|
| 416 |
|
|
| 402 |
| ||||||||
Other long-term assets |
|
| 1,891 |
|
|
| 1,987 |
|
|
| 333 |
|
|
| 378 |
|
Total assets |
| $ | 27,559 |
|
| $ | 25,913 |
|
| $ | 21,778 |
|
| $ | 21,025 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Accounts payable |
| $ | 797 |
|
| $ | 642 |
|
| $ | 576 |
|
| $ | 500 |
|
Revenues and royalties payable |
|
| 1,012 |
|
|
| 908 |
|
|
| 1,672 |
|
|
| 1,456 |
|
Short-term debt |
|
| 20 |
|
|
| — |
| ||||||||
Other current liabilities |
|
| 1,003 |
|
|
| 1,066 |
|
|
| 1,506 |
|
|
| 1,131 |
|
Total current liabilities |
|
| 2,832 |
|
|
| 2,616 |
|
|
| 3,754 |
|
|
| 3,087 |
|
Long-term debt |
|
| 10,383 |
|
|
| 10,154 |
|
|
| 6,471 |
|
|
| 6,482 |
|
Lease liabilities |
|
| 251 |
|
|
| 252 |
| ||||||||
Asset retirement obligations |
|
| 1,100 |
|
|
| 1,226 |
|
|
| 443 |
|
|
| 468 |
|
Other long-term liabilities |
|
| 645 |
|
|
| 894 |
|
|
| 974 |
|
|
| 1,050 |
|
Deferred income taxes |
|
| 665 |
|
|
| 648 |
|
|
| 450 |
|
|
| 287 |
|
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 |
|
| 66 |
|
|
| 66 |
| ||||||||
Additional paid-in capital |
|
| 7,207 |
|
|
| 7,237 |
|
|
| 7,371 |
|
|
| 7,636 |
|
Accumulated deficit |
|
| (428 | ) |
|
| (1,646 | ) | ||||||||
Accumulated other comprehensive earnings |
|
| 297 |
|
|
| 284 |
| ||||||||
Retained earnings |
|
| 2,013 |
|
|
| 1,692 |
| ||||||||
Accumulated other comprehensive loss |
|
| (131 | ) |
|
| (132 | ) | ||||||||
Treasury stock, at cost, 0.3 million shares in 2022 |
|
| (19 | ) |
|
| 0 |
| ||||||||
Total stockholders’ equity attributable to Devon |
|
| 7,129 |
|
|
| 5,927 |
|
|
| 9,300 |
|
|
| 9,262 |
|
Noncontrolling interests |
|
| 4,805 |
|
|
| 4,448 |
|
|
| 135 |
|
|
| 137 |
|
Total equity |
|
| 11,934 |
|
|
| 10,375 |
|
|
| 9,435 |
|
|
| 9,399 |
|
Total liabilities and equity |
| $ | 27,559 |
|
| $ | 25,913 |
|
| $ | 21,778 |
|
| $ | 21,025 |
|
See accompanying notes to consolidated financial statements
8
8
DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
| Additional |
|
| Retained |
|
| Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Other |
|
|
|
|
|
|
|
| |||||||||||||||||
|
| Common Stock |
|
| Paid-In |
|
| Earnings |
|
| Comprehensive |
|
| Treasury |
|
| Noncontrolling |
|
| Total |
|
|
|
|
|
| Additional |
|
|
|
|
| Comprehensive |
|
|
|
|
|
|
|
| |||||||||||||||||||||||
|
| Shares |
|
| Amount |
|
| Capital |
|
| (Accumulated Deficit) |
|
| Earnings |
|
| Stock |
|
| Interests |
|
| Equity |
|
| Common Stock |
|
| Paid-In |
| Retained |
| Earnings |
| Treasury |
| Noncontrolling |
| Total |
| ||||||||||||||||||||||||
|
| (Unaudited) |
|
| Shares |
|
| Amount |
|
| Capital |
|
| Earnings |
|
| (Loss) |
|
| Stock |
|
| Interests |
|
| Equity |
| |||||||||||||||||||||||||||||||||||||
|
| (Millions) |
|
| (Unaudited) |
| ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 March 31, 2022 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2021 |
| 663 |
|
| $ | 66 |
|
| $ | 7,636 |
|
| $ | 1,692 |
|
| $ | (132 | ) |
| $ | — |
|
| $ | 137 |
|
| $ | 9,399 |
| |||||||||||||||||||||||||||||||||
Net earnings |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,218 |
|
|
| — |
|
|
| — |
|
|
| 59 |
|
|
| 1,277 |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 989 |
|
|
| — |
|
|
| — |
|
|
| 6 |
|
|
| 995 |
| |
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| 13 |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1 |
| |
Restricted stock grants, net of cancellations |
|
| 1 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
|
| 2 |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1 |
| |
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| (43 | ) |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (305 | ) |
|
| — |
|
|
| (305 | ) | |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (43 | ) |
|
| — |
|
|
| — |
|
|
| 43 |
|
|
| — |
|
|
| — |
|
| (5 | ) |
|
| — |
|
|
| (286 | ) |
|
| — |
|
|
| — |
|
|
| 286 |
|
|
| — |
|
|
| — |
| |
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (95 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (95 | ) |
| — |
|
|
| — |
|
|
| — |
|
|
| (668 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (668 | ) | |
Share-based compensation |
|
| 1 |
|
|
| — |
|
|
| 96 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 96 |
|
| 1 |
|
|
| — |
|
|
| 20 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 20 |
| |
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 12 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 545 |
|
|
| 557 |
| ||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (247 | ) |
|
| (247 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (8 | ) |
|
| (8 | ) |
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 | ) | ||||||||||||||||||||||||||||||||
Balance as of March 31, 2022 |
|
| 661 |
|
| $ | 66 |
|
| $ | 7,371 |
|
| $ | 2,013 |
|
| $ | (131 | ) |
| $ | (19 | ) |
| $ | 135 |
|
| $ | 9,435 |
| ||||||||||||||||||||||||||||||||
Three Months Ended March 31, 2021 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||||||||||||||||||||||||||||||||||||||||||
Balance as of December 31, 2020 |
| 382 |
|
| $ | 38 |
|
| $ | 2,766 |
|
| $ | 208 |
|
| $ | (127 | ) |
| $ | — |
|
| $ | 134 |
|
| $ | 3,019 |
| |||||||||||||||||||||||||||||||||
Net earnings |
| — |
|
|
| — |
|
|
| — |
|
|
| 213 |
|
|
| — |
|
|
| — |
|
|
| 3 |
|
|
| 216 |
| |||||||||||||||||||||||||||||||||
Other comprehensive earnings, net of tax |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 48 |
|
|
| — |
|
|
| — |
|
|
| 48 |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| — |
|
|
| 23 |
| |
Restricted stock grants, net of cancellations |
|
| 3 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
| 4 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| |
Common stock repurchased |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| (23 | ) |
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (38 | ) |
|
| — |
|
|
| (38 | ) | |
Common stock retired |
|
| — |
|
|
| — |
|
|
| (23 | ) |
|
| — |
|
|
| — |
|
|
| 23 |
|
|
| — |
|
|
| — |
|
| (2 | ) |
|
| — |
|
|
| (38 | ) |
|
| — |
|
|
| — |
|
|
| 38 |
|
|
| — |
|
|
| — |
| |
Common stock dividends |
|
| — |
|
|
| — |
|
|
| (65 | ) |
|
| (125 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (190 | ) |
| — |
|
|
| — |
|
|
| — |
|
|
| (203 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (203 | ) | |
Common stock issued |
|
| 103 |
|
|
| 10 |
|
|
| 2,117 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,127 |
|
| 290 |
|
|
| 29 |
|
|
| 5,403 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5,432 |
| |
Share-based compensation |
|
| — |
|
|
| — |
|
|
| 142 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 142 |
|
| 1 |
|
|
| — |
|
|
| 41 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 41 |
| |
Subsidiary equity transactions |
|
| — |
|
|
| — |
|
|
| 320 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 896 |
|
|
| 1,216 |
| ||||||||||||||||||||||||||||||||
Distributions to noncontrolling interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (224 | ) |
|
| (224 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (4 | ) |
|
| (4 | ) |
Balance as of September 30, 2016 |
|
| 524 |
|
| $ | 52 |
|
| $ | 7,487 |
|
| $ | (1,977 | ) |
| $ | 278 |
|
| $ | — |
|
| $ | 4,221 |
|
| $ | 10,061 |
| ||||||||||||||||||||||||||||||||
Balance as of March 31, 2021 |
|
| 675 |
|
| $ | 67 |
|
| $ | 8,172 |
|
| $ | 218 |
|
| $ | (104 | ) |
| $ | — |
|
| $ | 133 |
|
| $ | 8,486 |
|
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 20162021 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, 2017March 31, 2022 and 20162021 and Devon’s financial position as of September 30, 2017.March 31, 2022.
Recently Adopted Accounting Standards
In Devon and WPX completed an all-stock merger of equals on January 2017, Devon adopted ASU 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting7, 2021. Its objective is to simplify several aspects On the closing date of the Merger, each share of WPX common stock was automatically converted into the right to receive 0.5165 of a share of Devon common stock. The transaction has been accounted for using the acquisition method of accounting, with Devon being treated as the accounting acquirer. See Note 2for share-basedfurther discussion.
Restricted Cash
As of March 31, 2022, Devon classified approximately $150 million of cash as restricted cash on the consolidated balance sheets for obligations retained related to the Barnett Shale assets and the Canadian business. Cash payments including income taxes when awards vest or are settled, statutory withholdingfor these charges related to the Barnett assets and forfeitures. As the resultCanada business total approximately $10 million per quarter.
Variable Interest Entity
Cotton Draw Midstream, L.L.C. (“CDM”) is a joint venture entity formed by Devon and an affiliate of adoption, Devon made certain income tax presentation changes, most notably prospectively presenting excess tax benefitsQL Capital Partners, LP. CDM provides gathering, compression and deficienciesdehydration services for natural gas production in the consolidated comprehensive statementsCotton Draw area of the Delaware Basin. 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 operating cash flowsnoncontrolling interests in the accompanying consolidated statements of cash flows. 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 retrospectively appliedincluded in, and disclosed parenthetically, if material, on Devon's consolidated balance sheets.
Investments
In conjunction with the new cash flow statement guidance dictatingMerger, Devon acquired an interest in Catalyst, which is a joint venture established among WPX, an affiliate of Howard Energy Partners, LLC (“HEP”) and certain other investors, to develop oil gathering and natural gas processing infrastructure in the presentation of shares exchanged for tax-withholding purposes as a financing activity. The adoptionStateline area of the new guidance didDelaware Basin. Under the terms of the arrangement, Devon and a holding company owned by the other joint venture investors each have a 50% voting interest in the joint venture legal entity, and HEP serves as the operator. Through 2038, Devon’s production from 50,000 net acres in the Stateline area of the Delaware Basin has been dedicated to Catalyst subject to fixed-fee oil gathering and natural gas processing agreements. The agreements do not materially impact the consolidated financial statementsinclude any minimum volume commitments. Devon accounts for the nine months ended September 30, 2017 or previously reported financial information but could have a more material future impact.
In January 2017, the FASB issued ASU 2017-04, Intangibles – Goodwill And Other (Topic 350), Simplifying the Test for Goodwill Impairment ("ASU 2017-04"). ASU 2017-04 simplifies the accounting for goodwill impairments by eliminating the requirement to compare the implied fair value of goodwill with its carrying amountinvestment in Catalyst 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 2017-04equity method investment.
Devon's investment in Catalyst is effective for annual reporting periods beginning after December 15, 2019, including any interim impairment testsshown 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 impactinvestments on the consolidated financial statements. Devon will perform future goodwill impairment tests according to ASU 2017-04.
Issued Accounting Standards Not Yet Adopted
The FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognitionbalance sheets and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition. This ASU provides guidance concerning the recognition and measurementDevon's share of revenue from contracts with customers. Its objective is to increase the usefulnessCatalyst earnings are reflected as a component of informationother, net in the financial statements regarding the nature, timing and uncertainty of revenues. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning in 2018, with early adoption permitted in 2017. Devon has not early adopted this ASU. The ASU is required to be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Devon intends to use the cumulative effect transition method and does not anticipate this ASU will have a material impact on its balance sheet or relatedaccompanying 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 ofcomprehensive earnings. Any presentation changes would have no impact on operating income, earnings or cash flows. Devon does not expect significant changes to its annual disclosures; however, Devon’s quarterly disclosures will expand upon adoption of this ASU. Devon has implemented a process to gather and provide the quarterly disclosures required by the ASU.
10
|
|
|
| Carrying Amount |
| |||||
Investments |
| % Interest |
| March 31, 2022 |
|
| December 31, 2021 |
| ||
Catalyst |
| 50% |
| $ | 361 |
|
| $ | 368 |
|
Other |
| Various |
|
| 55 |
|
|
| 34 |
|
Total |
|
|
| $ | 416 |
|
| $ | 402 |
|
10
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Disaggregation of Revenue
The following table presents revenue from contracts with customers that are disaggregated based on the type of good or service.
The FASB issued ASU 2016-02, Leases (Topic 842). This ASU will supersede the lease requirements in Topic 840, Leases. Its objective is to increase transparency
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Oil |
| $ | 2,406 |
|
| $ | 1,331 |
|
Gas |
|
| 307 |
|
|
| 202 |
|
NGL |
|
| 462 |
|
|
| 224 |
|
Oil, gas and NGL sales |
|
| 3,175 |
|
|
| 1,757 |
|
|
|
|
|
|
|
| ||
Oil |
|
| 776 |
|
|
| 499 |
|
Gas |
|
| 209 |
|
|
| 147 |
|
NGL |
|
| 335 |
|
|
| 175 |
|
Marketing and midstream revenues |
|
| 1,320 |
|
|
| 821 |
|
Total revenues from contracts with customers |
| $ | 4,495 |
|
| $ | 2,578 |
|
2. Acquisitions and comparability among organizations. This ASU provides guidance requiring lessees to recognize most leases on their balance sheet. Lessor accounting does not significantly change, except for some changes made to alignDivestitures
WPX Merger
On January 7, 2021, Devon and WPX completed an all-stock merger of equals. WPX was an oil and gas exploration and production company with new revenue recognition requirements. This ASU is effective for Devon beginning January 1, 2019 and will be applied using a modified retrospective transition method, which requires applying the new guidance to leases that exist or are entered into after the beginning of the earliest period in the financial statements. 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 playDelaware 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 was automatically converted into the right to receive 0.5165 of a share of Devon common stock. No fractional shares of Devon’s common stock were issued in the Merger, and holders of WPX common stock instead received cash in lieu of fractional shares of Devon common stock, if any. Based on the closing price of Devon’s common stock on January 7, 2021, the total value of Devon common stock issued to holders of WPX common stock as part of this transaction was approximately $5.4 billion. The Merger was structured as a tax-free reorganization for approximately $1.5 billion.United States federal income tax purposes. The final allocation of the total purchase price of WPX to the identifiable assets acquired and the liabilities assumed was finalized at December 31, 2021.
Divestitures
In the first quarter of 2021, Devon fundedcompleted the acquisition with $849sale of non-core assets in the Rockies for proceeds of $9 million, net of cash, afterpurchase price adjustments, and $659recognized a $35 million gain related to the sale. Devon received $4 million in contingent earnout payments related to this transaction in the first quarter of common equity shares. 2022 with the potential for up to an additional $4 million in the future. The purchase price allocation was approximately $1.3 billion to unproved properties and approximately $200 million to proved properties.
2017 Devon Asset Divestitures
In May 2017, Devon announced a program to divest approximately $1 billion of upstream assets. The non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. Estimatedtotal estimated proved reserves associated with these divested assets were less than 1% of total U.S. proved reserves.was approximately 3 MMBoe.
2016 Contingent Earnout Payments
Devon Asset Divestitures
In the second quarter of 2016, Devon divested non-core assets for approximately $200 million. Estimated proved reservesis entitled to contingent earnout payments associated with these assets were less than 1%the sale 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% of total U.S. proved reserves.
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 midstreamBarnett Shale assets in the Delaware Basin. 2020 with upside participation beginning at a $2.75 Henry Hub natural gas price or a $50 WTI oil price. The joint venture is initially owned 50.1% by EnLinkcontingent payment period commenced on January 1, 2021 and 49.9% by the joint venture partner. EnLink contributed approximately $244 millionhas a term of existing non-monetary assets to the joint venture and committed an additional $262four years. Devon received $65 million in capitalcontingent earnout payments related 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 beginningthis transaction 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 interest2022 and could receive up to an additional $195 million in Howard Energy Partnerscontingent earnout payments for the remaining performance periods depending on future commodity prices. The valuation of the future contingent earnout payments included within other current assets and other long-term assets in the March 31, 2022 consolidated balance sheet was approximately $190 million.$51 million and $60 million, respectively. The value was derived utilizing a Monte Carlo valuation model and qualifies as a level 3 fair value measurement.
|
|
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.collars and call options. 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,March 31, 2022, Devon did not have any open foreign exchangeinterest rate swap contracts.
1211
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Devon does not intend to hold or issue derivative financial instruments for speculative trading purposes and has elected not to designate any of its derivative instruments for hedge accounting treatment.
Counterparty Credit Risk
By using derivative financial instruments, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with investment-grade rated counterparties deemed by management to be competent and competitive market makers. Additionally, Devon’s derivative contracts generally contain provisions that provide for collateral payments if Devon’s or its counterparty’s credit rating falls below certain credit rating levels.
Commodity Derivatives
As of September 30, 2017,March 31, 2022, Devon neither held cash collateral of its counterparties 0r posted cash collateral to its counterparties. Given Devon's current credit ratings and the terms of the underlying contracts, Devon is not currently required to post collateral to its counterparties with respect to its open derivative positions, and we would not be required to post any such collateral as a result of any change to the amount of Devon's net liability for such positions.
Commodity Derivatives
As of March 31, 2022, Devon had the following open oil derivative positions. The first table presents Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second table presents Devon’s oil derivatives that settle against the respective indices noted within the table.
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
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 |
|
|
| 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 | ) |
|
| Price Swaps |
|
| Price Collars |
|
| ||||||||||||||
Period |
| Volume |
|
| Weighted |
|
| Volume |
|
| Weighted |
|
| Weighted |
|
| |||||
Q2-Q4 2022 |
|
| 35,258 |
|
| $ | 44.50 |
|
|
| 37,658 |
|
| $ | 55.56 |
|
| $ | 74.84 |
|
|
Q1-Q4 2023 |
|
| — |
|
| $ | — |
|
|
| 6,193 |
|
| $ | 61.32 |
|
| $ | 97.65 |
|
|
|
| Oil Basis Swaps |
| |||||||
Period |
| Index |
| Volume |
|
| Weighted Average |
| ||
Q2-Q4 2022 |
| BRENT |
|
| 1,000 |
|
| $ | (7.75 | ) |
Q2-Q4 2022 |
| NYMEX Roll |
|
| 29,000 |
|
| $ | 0.45 |
|
Q1-Q4 2023 |
| Midland Sweet |
|
| 3,000 |
|
| $ | 0.73 |
|
As of September 30, 2017,March 31, 2022, 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 and the end of month NYMEX index. The second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.
|
| Price Swaps (1) |
|
| Price Collars (2) |
| ||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average |
| |||||
Q2-Q4 2022 |
|
| 110,000 |
|
| $ | 2.79 |
|
|
| 209,509 |
|
| $ | 2.98 |
|
| $ | 4.30 |
|
Q1-Q4 2023 |
|
| 4,959 |
|
| $ | 3.65 |
|
|
| 58,901 |
|
| $ | 3.38 |
|
| $ | 5.64 |
|
|
| Price Swaps |
|
| Price Collars |
| ||||||||||||||
Period |
| Volume (MMBtu/d) |
|
| Weighted Average Price ($/MMBtu) |
|
| Volume (MMBtu/d) |
|
| Weighted Average Floor Price ($/MMBtu) |
|
| Weighted Average Ceiling Price ($/MMBtu) |
| |||||
Q4 2017 |
|
| 331,196 |
|
| $ | 3.21 |
|
|
| 455,000 |
|
| $ | 3.03 |
|
| $ | 3.41 |
|
Q1-Q4 2018 |
|
| 261,888 |
|
| $ | 3.09 |
|
|
| 149,982 |
|
| $ | 2.99 |
|
| $ | 3.30 |
|
Q1-Q4 2019 |
|
| 6,164 |
|
| $ | 3.08 |
|
|
| 8,630 |
|
| $ | 2.92 |
|
| $ | 3.22 |
|
13
12
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| Natural Gas Basis Swaps |
| |||||||
Period |
| Index |
| Volume |
|
| Weighted Average |
| ||
Q2-Q4 2022 |
| El Paso Natural Gas |
|
| 40,000 |
|
| $ | (0.82 | ) |
Q2-Q4 2022 |
| Houston Ship Channel |
|
| 10,000 |
|
| $ | (0.17 | ) |
Q2-Q4 2022 |
| WAHA |
|
| 70,000 |
|
| $ | (0.57 | ) |
Q1-Q4 2023 |
| El Paso Natural Gas |
|
| 60,000 |
|
| $ | (1.50 | ) |
Q1-Q4 2023 |
| WAHA |
|
| 70,000 |
|
| $ | (0.51 | ) |
Q1-Q4 2024 |
| WAHA |
|
| 40,000 |
|
| $ | (0.51 | ) |
|
| 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 | ) |
As of September 30, 2017,March 31, 2022, Devon had the followingdid not have any 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 |
| ||||||||||||||
Period |
| Product |
| Volume (Bbls/d) |
|
| Weighted Average Price ($/Bbl) |
|
| Volume (Bbls/d) |
|
| Weighted Average Floor Price ($/Bbl) |
|
| Weighted Average Ceiling Price ($/Bbl) |
| |||||
Q4 2017 |
| Propane |
|
| 2,663 |
|
| $ | 31.98 |
|
|
| 1,000 |
|
| $ | 28.35 |
|
| $ | 30.45 |
|
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
All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the consolidated balance sheets. Amounts related to contracts allowed to be netted upon payment subject to a master netting arrangement with the same counterparty are reported on a net basis in the consolidated balance sheets. The followingtables below present a summary of these positions as of March 31, 2022 and December 31, 2021.
| March 31, 2022 |
|
| December 31, 2021 |
|
|
| ||||||||||||||||||
| Gross Fair Value |
|
| Amounts Netted |
|
| Net Fair Value |
|
| Gross Fair Value |
|
| Amounts Netted |
|
| Net Fair Value |
|
| Balance Sheet Classification | ||||||
Commodity derivatives: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Short-term derivative asset | $ | 15 |
|
| $ | (14 | ) |
| $ | 1 |
|
| $ | 6 |
|
| $ | (4 | ) |
| $ | 2 |
|
| Other current assets |
Long-term derivative asset |
| 31 |
|
|
| — |
|
|
| 31 |
|
|
| 6 |
|
|
| — |
|
|
| 6 |
|
| Other long-term assets |
Short-term derivative liability |
| (953 | ) |
|
| 14 |
|
|
| (939 | ) |
|
| (579 | ) |
|
| 4 |
|
|
| (575 | ) |
| Other current liabilities |
Long-term derivative liability |
| (1 | ) |
|
| — |
|
|
| (1 | ) |
|
| (2 | ) |
|
| — |
|
|
| (2 | ) |
| Other long-term liabilities |
Total derivative liability | $ | (908 | ) |
| $ | — |
|
| $ | (908 | ) |
| $ | (569 | ) |
| $ | — |
|
| $ | (569 | ) |
|
|
The table below 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 sheet caption.
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Commodity derivative assets: |
|
|
|
|
|
|
|
|
Other current assets |
| $ | 39 |
|
| $ | 9 |
|
Other long-term assets |
|
| 4 |
|
|
| 1 |
|
Interest rate derivative assets: |
|
|
|
|
|
|
|
|
Other current assets |
|
| 1 |
|
|
| 1 |
|
Total derivative assets |
| $ | 44 |
|
| $ | 11 |
|
Commodity derivative liabilities: |
|
|
|
|
|
|
|
|
Other current liabilities |
| $ | 53 |
|
| $ | 187 |
|
Other long-term liabilities |
|
| 7 |
|
|
| 16 |
|
Interest rate derivative liabilities: |
|
|
|
|
|
|
|
|
Other current liabilities |
|
| 1 |
|
|
| — |
|
Other long-term liabilities |
|
| 61 |
|
|
| 41 |
|
Total derivative liabilities |
| $ | 122 |
|
| $ | 244 |
|
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
In the second quarter of 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan, awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available for issuance under the 2015 Plan (including shares subject to outstanding awards under the 2015 Plan that are transferred to the 2017 Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock options, restricted stock awards or units, Canadian restricted stock units, performance units and stock appreciation rights to eligible employees. The 2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.
The following table 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 20162021 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 awards5 and is included in restructuring and transaction costs in the accompanying consolidated comprehensive statements of comprehensive earnings.
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
G&A |
| $ | 20 |
|
| $ | 20 |
|
Restructuring and transaction costs |
|
| 0 |
|
|
| 21 |
|
Total |
| $ | 20 |
|
| $ | 41 |
|
Related income tax benefit |
| $ | 17 |
|
| $ | 0 |
|
13
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| 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 |
|
Under its approved long-term incentive plan, Devon grantedgrants share-based awards to certain employees in the first nine months of 2017.its employees. 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 Awards & Units |
|
| Performance Share Units |
| ||||||||||
|
| Awards/Units |
|
| Weighted |
|
| Units |
|
| Weighted |
| ||||
|
| (Thousands, except fair value data) |
| |||||||||||||
Unvested at 12/31/21 |
|
| 7,656 |
|
| $ | 22.15 |
|
|
| 2,076 |
|
| $ | 24.12 |
|
Granted |
|
| 1,249 |
|
| $ | 52.23 |
|
|
| 964 |
|
| $ | 44.05 |
|
Vested |
|
| (2,476 | ) |
| $ | 23.02 |
|
|
| (1,194 | ) |
| $ | 28.91 |
|
Forfeited |
|
| (8 | ) |
| $ | 29.42 |
|
|
| 0 |
|
| $ | 0 |
|
Unvested at 3/31/22 |
|
| 6,421 |
|
| $ | 27.66 |
|
|
| 1,846 |
| (1) | $ | 31.43 |
|
|
| Restricted Stock |
|
| Performance-Based |
|
| Performance |
| ||||||||||||||||||
|
| Awards and Units |
|
| Restricted Stock Awards |
|
| Share Units |
| ||||||||||||||||||
|
| Awards and Units |
|
| Weighted Average Grant-Date Fair Value |
|
| Awards |
|
| Weighted Average Grant-Date Fair Value |
|
| Units |
|
|
|
|
| Weighted Average Grant-Date Fair Value |
| ||||||
|
| (Thousands, except fair value data) |
| ||||||||||||||||||||||||
Unvested at 12/31/16 |
|
| 6,407 |
|
| $ | 34.40 |
|
|
| 585 |
|
| $ | 37.60 |
|
|
| 2,604 |
|
|
|
|
| $ | 46.66 |
|
Granted |
|
| 2,691 |
|
| $ | 44.87 |
|
|
| 223 |
|
| $ | 44.85 |
|
|
| 1,010 |
|
|
|
|
| $ | 52.58 |
|
Vested |
|
| (2,321 | ) |
| $ | 39.51 |
|
|
| (233 | ) |
| $ | 41.27 |
|
|
| (832 | ) |
|
|
|
| $ | 78.19 |
|
Forfeited |
|
| (252 | ) |
| $ | 36.06 |
|
|
| — |
|
| $ | — |
|
|
| (24 | ) |
|
|
|
| $ | 40.70 |
|
Unvested at 9/30/17 |
|
| 6,525 |
|
| $ | 36.83 |
|
|
| 575 |
|
| $ | 38.92 |
|
|
| 2,758 |
|
| (1 | ) |
| $ | 41.21 |
|
|
|
The following table presents the assumptions related to the performance share units granted in 2017,2022, as indicated in the previous summary table.
|
| 2017 |
|
| 2022 |
| ||||||||
Grant-date fair value |
| $ | 51.05 |
| — |
| $ | 53.12 |
|
| $ | 68.68 |
| |
Risk-free interest rate |
| 1.50% |
|
|
| 1.81 | % | |||||||
Volatility factor |
| 45.8% |
|
|
| 70.1 | % | |||||||
Contractual term (years) |
| 2.89 |
|
|
| 2.89 |
|
16
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associated with unvested awards and units as of September 30, 2017.March 31, 2022.
|
| Restricted Stock |
|
| Performance |
| ||
|
| Awards/Units |
|
| Share Units |
| ||
Unrecognized compensation cost |
| $ | 122 |
|
| $ | 32 |
|
Weighted average period for recognition (years) |
|
| 3.0 |
|
|
| 2.1 |
|
5. Restructuring and Transaction Costs
|
|
|
|
|
| Performance-Based |
|
|
|
|
| |
|
| Restricted Stock |
|
| Restricted Stock |
|
| Performance |
| |||
|
| Awards and Units |
|
| Awards |
|
| Share Units |
| |||
Unrecognized compensation cost (millions) |
| $ | 160 |
|
| $ | 6 |
|
| $ | 35 |
|
Weighted average period for recognition (years) |
|
| 2.5 |
|
|
| 1.8 |
|
|
| 2.0 |
|
The following table summarizes Devon’s restructuring and transaction costs.
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Restructuring costs |
| $ | 0 |
|
| $ | 143 |
|
Transaction costs |
|
| 0 |
|
|
| 46 |
|
Total costs |
| $ | 0 |
|
| $ | 189 |
|
EnLink Share-Based Awards
In March 2017,conjunction with the General Partner and EnLink issued restricted incentive units as bonus payments to officers and certain employees. The combined grant fair value was $10Merger closing, Devon recognized $143 million and the total cost was recognized inof restructuring expenses during the first quarter of 2017 due2021 related to the awardsemployee severance and termination benefits, settlements and curtailments from defined retirement benefits and contract terminations. Of these expenses, $37 million and $21 million resulted from settlements and curtailments of defined retirement benefits and accelerated vesting immediately.
The following table presents a summary of the unrecognized compensation cost and the related weighted average recognition period associatedshare-based grants, respectively, which were non-cash charges. Additionally, in conjunction with the General Partner’sMerger closing, Devon recognized $46 million of transaction costs primarily comprised of bank, legal and EnLink’s unvested restricted incentive units and performance units as of September 30, 2017.accounting fees.
|
| 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 |
|
|
|
The following table presents the components of asset impairments.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
U.S. oil and gas assets |
| $ | — |
|
| $ | 317 |
|
| $ | — |
|
| $ | 2,810 |
|
Canada oil and gas assets |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,166 |
|
EnLink goodwill |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 873 |
|
Other assets |
|
| 2 |
|
|
| 2 |
|
|
| 9 |
|
|
| 2 |
|
Total asset impairments |
| $ | 2 |
|
| $ | 319 |
|
| $ | 9 |
|
| $ | 4,851 |
|
Oil and Gas Impairments
Under the full cost method of accounting, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the full cost “ceiling” at the end of each quarter. The ceiling is calculated separately for each country and is based on the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10% per annum, net of related tax effects. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months.
The oil and gas impairments in 2016 resulted from declines in the U.S. and Canada full cost ceilings. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for oil, bitumen, gas and NGLs, which significantly reduced proved reserves values and, to a lesser degree, proved reserves.
EnLink Goodwill Impairments
In the first quarter of 2016, EnLink recognized goodwill impairments. See Note 12 for additional details.
1714
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
6.Restructuring and Transaction Costs
The following table summarizes Devon’s restructuring and transaction costsliabilities.
|
| Other |
|
| Other |
|
|
|
| |||
|
| Current |
|
| Long-term |
|
|
|
| |||
|
| Liabilities |
|
| Liabilities |
|
| Total |
| |||
Balance as of December 31, 2021 |
| $ | 38 |
|
| $ | 111 |
|
| $ | 149 |
|
Changes related to prior years' restructurings |
|
| (4 | ) |
|
| (6 | ) |
|
| (10 | ) |
Balance as of March 31, 2022 |
| $ | 34 |
|
| $ | 105 |
|
| $ | 139 |
|
|
|
|
|
|
|
|
|
|
| |||
Balance as of December 31, 2020 |
| $ | 35 |
|
| $ | 137 |
|
| $ | 172 |
|
Changes related to prior years' restructurings |
|
| 59 |
|
|
| (7 | ) |
|
| 52 |
|
Balance as of March 31, 2021 |
| $ | 94 |
|
| $ | 130 |
|
| $ | 224 |
|
6. Other, Net
The following table summarizes Devon's other expenses (income) presented in the accompanying consolidated comprehensive statement of earnings.
|
| September 30, 2016 |
| |||||
|
| Three Months Ended |
|
| Nine Months Ended |
| ||
|
| (Millions) |
| |||||
2016 reduction in workforce: |
|
|
|
|
|
|
|
|
Employee related costs |
| $ | (7 | ) |
| $ | 229 |
|
Lease obligations |
|
| — |
|
|
| 17 |
|
Asset impairments |
|
| — |
|
|
| 3 |
|
Transaction costs |
|
| 2 |
|
|
| 17 |
|
Restructuring and transaction costs |
| $ | (5 | ) |
| $ | 266 |
|
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Estimated future obligation under a performance guarantee |
| $ | (96 | ) |
| $ | 0 |
|
Ukraine charitable pledge |
|
| 20 |
|
|
| 0 |
|
Asset retirement obligation accretion |
|
| 7 |
|
|
| 7 |
|
Severance and other non-income tax refunds |
|
| (3 | ) |
|
| (36 | ) |
Other |
|
| 11 |
|
|
| 0 |
|
Total |
| $ | (61 | ) |
| $ | (29 | ) |
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 |
|
Reductionfirst quarter of 2022 includes a $96 million benefit related to the revision of a future obligation under a performance guarantee liability for previously divested assets. Due to improved commodity prices and market conditions, the purchaser of these assets was able to fully satisfy the $35 million obligation due in Workforce
In the first nine monthsquarter of 2016,2022. Further, as of March 31, 2022, Devon recognized $229 million in employee-related costs associated with a reduction in workforce. Of these employee-related costs, approximately $60 million resulted from accelerated vesting of share-based grants, which are noncash charges. Additionally, approximately $30 million resulted fromalso reduced the estimated settlements of defined retirement benefits.
As a resultfuture exposure 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 representperformance guarantee by $61 million based on probability-weighted cash flows for 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 closingremainder of the acquisitions discussed in Note 2.contract term of four years.
The first quarter of 2022 also includes a $20 million pledge for humanitarian relief for the Ukrainian people and surrounding countries supporting refugees.
18
The first quarter of 2021 includes a Texas severance tax refund of $36 million related to prior periods.
15
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
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 March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Earnings (loss) before income taxes |
| $ | 1,262 |
|
| $ | (32 | ) |
|
|
|
|
|
|
| ||
Current income tax expense (benefit) |
| $ | 103 |
|
| $ | (5 | ) |
Deferred income tax expense (benefit) |
|
| 164 |
|
|
| (243 | ) |
Total income tax expense (benefit) |
| $ | 267 |
|
| $ | (248 | ) |
|
| 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 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. statutory income tax rate |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
|
| 35 | % |
Deferred tax asset valuation allowance |
|
| (9 | %) |
|
| (35 | %) |
|
| (25 | %) |
|
| (20 | %) |
Non-deductible goodwill impairments |
|
| 0 | % |
|
| 6 | % |
|
| 0 | % |
|
| (9 | %) |
Change in unrecognized tax benefits |
|
| 3 | % |
|
| 7 | % |
|
| 1 | % |
|
| (2 | %) |
Taxation on Canadian operations |
|
| (1 | %) |
|
| 0 | % |
|
| 0 | % |
|
| (3 | %) |
State income taxes |
|
| 0 | % |
|
| 2 | % |
|
| 0 | % |
|
| 1 | % |
Other |
|
| (19 | %) |
|
| 0 | % |
|
| (7 | %) |
|
| 3 | % |
Effective income tax rate |
|
| 9 | % |
|
| 15 | % |
|
| 4 | % |
|
| 5 | % |
U.S. statutory income tax rate |
|
| 21 | % |
|
| 21 | % |
State income taxes |
|
| 1 | % |
|
| (1 | %) |
Deferred tax asset valuation allowance |
|
| 0 | % |
|
| 791 | % |
Other |
|
| (1 | %) |
|
| (48 | %) |
Effective income tax rate |
|
| 21 | % |
|
| 763 | % |
Prior to December 31, 2021, Devon estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur.
Throughout 2016 and through the first nine months of 2017, Devon continued to maintainmaintained a 100% valuation allowance against itsall U.S. federal deferred tax assets. Devon recognized approximately $250 million of deferred tax liabilities to account for the Merger. The recognition of these deferred tax liabilities caused a decrease to Devon’s net deferred tax assets resulting from prior year cumulative financial losses largely dueand a corresponding decrease to full cost impairments. Furthermore, a partialthe valuation allowance continues to be held against certain Canadian segmentDevon had recognized on its U.S. federal deferred tax assets.
Devon provided an additional $796 million to the U.S. segment valuation allowanceassets 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 recorded2021.
Due to significant increases in commodity pricing and projections of future income, in the fourth quarter of 2021, Devon reassessed its evaluation of the realizability of deferred tax assets in future years and determined that a $71 million partial valuation allowance. Devon reduced its U.S. segmentfederal valuation allowance by $348 million in the first nine months of 2017 based on the financial income recorded during the period.was no longer necessary at December 31, 2021.
Also inIn the table above, the “other”"other" effect for 2021 is composed primarily composed of permanent differences for which dollar amounts do not increase or decreaserelated to costs incurred in relation toconnection with the change in pre-tax earnings. Generally, suchMerger. Such items have an insignificant impact on our effectiverepresent $15 million of income tax rate. However, these items have a more noticeable impact to our rateexpense in the third quarter of 2017 due to lower relative earnings during the period. During the third quarter of 2017, “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.2021.
Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal course of business. The timing of resolution of income tax examinations is uncertain as are the amounts and timing of tax payments that are part of any audit settlement process. Devon believes that within the next 12 months it is reasonably possible that certain tax examinations will be resolved by settlement with the taxing authorities.
19
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table reconciles net earnings (loss) attributable to Devon and weighted-average common shares outstanding used in the calculations of basic and diluted net earnings (loss) per share.
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||||
|
| (Millions, except per share amounts) |
|
| 2022 |
|
| 2021 |
| |||||||||||||||
Net earnings (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net earnings (loss) attributable to Devon |
| $ | 228 |
|
| $ | 993 |
|
| $ | 1,218 |
|
| $ | (3,633 | ) | ||||||||
Net earnings: |
|
|
|
|
| |||||||||||||||||||
Net earnings |
| $ | 989 |
|
| $ | 213 |
| ||||||||||||||||
Attributable to participating securities |
|
| (2 | ) |
|
| (11 | ) |
|
| (13 | ) |
|
| (1 | ) |
|
| (16 | ) |
|
| (2 | ) |
Basic and diluted earnings (loss) |
| $ | 226 |
|
| $ | 982 |
|
| $ | 1,205 |
|
| $ | (3,634 | ) | ||||||||
Basic and diluted earnings |
| $ | 973 |
|
| $ | 211 |
| ||||||||||||||||
Common shares: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||
Common shares outstanding - total |
|
| 526 |
|
|
| 524 |
|
|
| 525 |
|
|
| 509 |
|
| 663 |
|
|
| 654 |
| |
Attributable to participating securities |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (6 | ) |
|
| (7 | ) |
|
| (5 | ) |
Common shares outstanding - basic |
|
| 520 |
|
|
| 518 |
|
|
| 519 |
|
|
| 503 |
|
| 656 |
|
|
| 649 |
| |
Dilutive effect of potential common shares issuable |
|
| 3 |
|
|
| 3 |
|
|
| 3 |
|
|
| — |
|
|
| 2 |
|
|
| 2 |
|
Common shares outstanding - diluted |
|
| 523 |
|
|
| 521 |
|
|
| 522 |
|
|
| 503 |
|
|
| 658 |
|
|
| 651 |
|
Net earnings (loss) per share attributable to Devon: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||
Net earnings per share: |
|
|
|
|
|
| ||||||||||||||||||
Basic |
| $ | 0.43 |
|
| $ | 1.90 |
|
| $ | 2.32 |
|
| $ | (7.22 | ) |
| $ | 1.48 |
|
| $ | 0.33 |
|
Diluted |
| $ | 0.43 |
|
| $ | 1.89 |
|
| $ | 2.31 |
|
| $ | (7.22 | ) |
| $ | 1.48 |
|
| $ | 0.32 |
|
Antidilutive options (1) |
|
| 2 |
|
|
| 3 |
|
|
| 2 |
|
|
| 3 |
|
|
|
|
|
Components of other comprehensive earnings consist of the following:
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
Foreign currency translation: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated foreign currency translation |
| $ | 456 |
|
| $ | 450 |
|
| $ | 456 |
|
| $ | 424 |
|
Change in cumulative translation adjustment |
|
| 17 |
|
|
| (1 | ) |
|
| 31 |
|
|
| 52 |
|
Income tax benefit (expense) |
|
| (16 | ) |
|
| 3 |
|
|
| (30 | ) |
|
| (24 | ) |
Ending accumulated foreign currency translation |
|
| 457 |
|
|
| 452 |
|
|
| 457 |
|
|
| 452 |
|
Pension and postretirement benefit plans: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning accumulated pension and postretirement benefits |
|
| (163 | ) |
|
| (185 | ) |
|
| (172 | ) |
|
| (194 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 5 |
|
|
| 7 |
|
|
| 14 |
|
|
| 20 |
|
Income tax benefit |
|
| — |
|
|
| 4 |
|
|
| — |
|
|
| — |
|
Ending accumulated pension and postretirement benefits |
|
| (158 | ) |
|
| (174 | ) |
|
| (158 | ) |
|
| (174 | ) |
Other |
|
| (2 | ) |
|
| — |
|
|
| (2 | ) |
|
| — |
|
Accumulated other comprehensive earnings, net of tax |
| $ | 297 |
|
| $ | 278 |
|
| $ | 297 |
|
| $ | 278 |
|
|
|
2016
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
9. Other Comprehensive Earnings (Loss)
|
Components of other comprehensive earnings (loss) consist of the following:
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Pension and postretirement benefit plans: |
|
|
|
|
|
| ||
Beginning accumulated pension and postretirement benefits |
| $ | (132 | ) |
| $ | (127 | ) |
Recognition of net actuarial loss and prior service cost in earnings (1) |
|
| 1 |
|
|
| 1 |
|
Settlement of pension benefits (2) |
|
| 0 |
|
|
| 15 |
|
Other (3) |
|
| 0 |
|
|
| 7 |
|
Accumulated other comprehensive loss, net of tax |
| $ | (131 | ) |
| $ | (104 | ) |
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
Net change in working capital accounts, net of assets and liabilities assumed: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
| $ | (215 | ) |
| $ | 81 |
|
| $ | (85 | ) |
| $ | 87 |
|
Income taxes receivable |
|
| — |
|
|
| 6 |
|
|
| 8 |
|
|
| 107 |
|
Other current assets |
|
| 12 |
|
|
| 98 |
|
|
| (43 | ) |
|
| 242 |
|
Accounts payable |
|
| 48 |
|
|
| (34 | ) |
|
| 98 |
|
|
| (185 | ) |
Revenues and royalties payable |
|
| 63 |
|
|
| 40 |
|
|
| 92 |
|
|
| 34 |
|
Other current liabilities |
|
| 99 |
|
|
| (54 | ) |
|
| 24 |
|
|
| (77 | ) |
Net change in working capital |
| $ | 7 |
|
| $ | 137 |
|
| $ | 94 |
|
| $ | 208 |
|
Interest paid (net of capitalized interest) |
| $ | 49 |
|
| $ | 113 |
|
| $ | 285 |
|
| $ | 402 |
|
Income taxes paid (received) |
| $ | — |
|
| $ | (7 | ) |
| $ | (1) |
|
| $ | (130 | ) |
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Changes in assets and liabilities, net: |
|
|
|
|
|
| ||
Accounts receivable |
| $ | (457 | ) |
| $ | (63 | ) |
Other current assets |
|
| 64 |
|
|
| (10 | ) |
Other long-term assets |
|
| 66 |
|
|
| (10 | ) |
Accounts payable and revenues and royalties payable |
|
| 247 |
|
|
| 16 |
|
Other current liabilities |
|
| 8 |
|
|
| (33 | ) |
Other long-term liabilities |
|
| (71 | ) |
|
| (27 | ) |
Total |
| $ | (143 | ) |
| $ | (127 | ) |
Supplementary cash flow data: |
|
|
|
|
|
| ||
Interest paid |
| $ | 100 |
|
| $ | 114 |
|
Income taxes refunded |
| $ | (23 | ) |
| $ | (6 | ) |
Devon’s acquisition of certain STACK assets during the first three months of 2016 included the noncash issuance of Devon common stock. See Note 2 for additional details.
EnLink’s acquisition of Anadarko Basin gathering and processing midstream assets during the first quarter of 2016 included the noncash issuance of General Partner common units. Additionally, EnLink’s formation of a joint venture during the third quarter of 2016 included non-monetary asset contributions. See Note 2 for additional details.
| 11. Accounts Receivable |
Components of accounts receivable include the following:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||||||||||
|
| (Millions) |
|
| March 31, 2022 |
|
| December 31, 2021 |
| |||||||
Oil, gas and NGL sales |
| $ | 528 |
|
| $ | 487 |
|
| $ | 1,296 |
| $ | 984 |
| |
Joint interest billings |
|
| 111 |
|
|
| 110 |
|
| 161 |
| 158 |
| |||
Marketing and midstream revenues |
|
| 792 |
|
|
| 708 |
|
| 496 |
| 370 |
| |||
Other |
|
| 44 |
|
|
| 69 |
|
|
| 56 |
|
|
| 38 |
|
Gross accounts receivable |
|
| 1,475 |
|
|
| 1,374 |
|
| 2,009 |
| 1,550 |
| |||
Allowance for doubtful accounts |
|
| (13 | ) |
|
| (18 | ) |
|
| (7 | ) |
|
| (7 | ) |
Net accounts receivable |
| $ | 1,462 |
|
| $ | 1,356 |
|
| $ | 2,002 |
|
| $ | 1,543 |
|
|
|
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.
2117
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.
|
| March 31, 2022 |
|
| December 31, 2021 |
| ||
Property and equipment: |
|
|
|
|
|
| ||
Proved |
| $ | 38,524 |
|
| $ | 38,051 |
|
Unproved and properties under development |
|
| 1,101 |
|
|
| 1,081 |
|
Total oil and gas |
|
| 39,625 |
|
|
| 39,132 |
|
Less accumulated DD&A |
|
| (26,059 | ) |
|
| (25,596 | ) |
Oil and gas property and equipment, net |
|
| 13,566 |
|
|
| 13,536 |
|
Other property and equipment |
|
| 2,192 |
|
|
| 2,139 |
|
Less accumulated DD&A |
|
| (684 | ) |
|
| (667 | ) |
Other property and equipment, net (1) |
|
| 1,508 |
|
|
| 1,472 |
|
Property and equipment, net |
| $ | 15,074 |
|
| $ | 15,008 |
|
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Customer relationships |
| $ | 1,796 |
|
| $ | 1,796 |
|
Accumulated amortization |
|
| (202 | ) |
|
| (172 | ) |
Net intangibles |
| $ | 1,594 |
|
| $ | 1,624 |
|
The weighted-average amortization period for other intangible assets is 15 years. Amortization expense for intangibles was $37(1)
See below for the three months ended September 30, 2017 and 2016, respectively, and $96 million and $87 million for the nine months ended September 30, 2017 and 2016, respectively. The remaining amortization expense is estimated to be $123 million for each of the next five years.
|
|
Components of other current liabilities include the following:
| September 30, 2017 |
|
| December 31, 2016 |
| ||
| (Millions) |
| |||||
Installment payment - see Note 2 | $ | 243 |
|
| $ | 249 |
|
Accrued interest payable |
| 204 |
|
|
| 130 |
|
Income taxes payable |
| 197 |
|
|
| 32 |
|
Derivative liabilities |
| 54 |
|
|
| 187 |
|
Restructuring liabilities |
| 20 |
|
|
| 48 |
|
Other |
| 285 |
|
|
| 420 |
|
Other current liabilities | $ | 1,003 |
|
| $ | 1,066 |
|
|
|
Aa summary of debt instruments and balances. The notes and debentures are senior, unsecured obligations of Devon.
|
| March 31, 2022 |
|
| December 31, 2021 |
| ||
8.25% due August 1, 2023 |
| $ | 242 |
|
| $ | 242 |
|
5.25% due September 15, 2024 |
|
| 472 |
|
|
| 472 |
|
5.85% due December 15, 2025 |
|
| 485 |
|
|
| 485 |
|
7.50% due September 15, 2027 |
|
| 73 |
|
|
| 73 |
|
5.25% due October 15, 2027 |
|
| 390 |
|
|
| 390 |
|
5.875% due June 15, 2028 |
|
| 325 |
|
|
| 325 |
|
4.50% due January 15, 2030 |
|
| 585 |
|
|
| 585 |
|
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 premium (discount) on debentures and notes |
|
| 137 |
|
|
| 149 |
|
Debt issuance costs |
|
| (29 | ) |
|
| (30 | ) |
Total long-term debt |
| $ | 6,471 |
|
| $ | 6,482 |
|
Retirement of Senior Notes
In the first quarter of 2021, Devon redeemed $43 million of the 6.00% senior notes due 2022, $175 million of the 5.875% senior notes due 2028 and $315 million of the 4.50% senior notes due 2030. In the first quarter of 2021, Devon recognized $20 million of gains on early retirement of debt, consisting of $47 million of non-cash premium accelerations, partially offset by $27 million of cash retirement costs. The gain on early retirement is as follows:
|
| September 30, 2017 |
|
| December 31, 2016 |
| ||
|
| (Millions) |
| |||||
Devon debt: |
|
|
|
|
|
|
|
|
Debentures and notes |
| $ | 6,933 |
|
| $ | 6,933 |
|
Net discount on debentures and notes |
|
| (30 | ) |
|
| (30 | ) |
Debt issuance costs |
|
| (41 | ) |
|
| (44 | ) |
Total Devon debt |
|
| 6,862 |
|
|
| 6,859 |
|
EnLink debt: |
|
|
|
|
|
|
|
|
Credit facilities |
|
| 74 |
|
|
| 148 |
|
Debentures and notes |
|
| 3,500 |
|
|
| 3,163 |
|
Net premium (discount) on debentures and notes |
|
| (6 | ) |
|
| 9 |
|
Debt issuance costs |
|
| (27 | ) |
|
| (25 | ) |
Total EnLink debt |
|
| 3,541 |
|
|
| 3,295 |
|
Total debt |
|
| 10,403 |
|
|
| 10,154 |
|
Less amount classified as short-term debt (1) |
|
| 20 |
|
|
| — |
|
Total long-term debt |
| $ | 10,383 |
|
| $ | 10,154 |
|
|
|
included in net financing costs in the consolidated comprehensive statements of earnings.
22
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Devon has a $3.0$3.0 billion Senior Credit Facility. As of September 30, 2017,March 31, 2022, 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%65%. Under the terms of the credit agreement, total capitalization is adjusted to add back noncash
18
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
non-cash financial write-downs such as full cost ceiling impairments or goodwill impairments. As of September 30, 2017,March 31, 2022, Devon was in compliance with this covenant with a debt-to-capitalization ratio of 18.9%24.7%.
Retirement of Senior Notes
In the third quarter of 2016, 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 $500 million of 5.45% unsecured senior notes due in 2047. The proceeds were used to repay outstanding borrowings under its revolving credit facility and for general partnership purposes. Additionally, in the second quarter of 2017, EnLink redeemed its $163 million 7.125% senior unsecured notes due in 2022. EnLink redeemed the notes at 103.6% of the principal amount, plus accrued unpaid interest, for aggregate cash consideration of $174 million, which resulted in a gain on extinguishment of debt of $9 million during the second quarter of 2017. The gain is included in net financing costs in the consolidated comprehensive statement of earnings.
Net Financing Costs
The following schedule includes the components of net financing costs.
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Interest based on debt outstanding |
| $ | 92 |
|
| $ | 105 |
|
Gain on early retirement of debt |
|
| — |
|
|
| (20 | ) |
Interest income |
|
| (1 | ) |
|
| (1 | ) |
Other |
|
| (6 | ) |
|
| (7 | ) |
Total net financing costs |
| $ | 85 |
|
| $ | 77 |
|
|
| 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 |
|
14. Leases
The following table presents Devon’s right-of-use assets and lease liabilities as of March 31, 2022 and December 31, 2021.
|
| March 31, 2022 |
|
| December 31, 2021 |
| ||||||||||||||||||
|
| Finance |
|
| Operating |
|
| Total |
|
| Finance |
|
| Operating |
|
| Total |
| ||||||
Right-of-use assets |
| $ | 209 |
|
| $ | 20 |
|
| $ | 229 |
|
| $ | 211 |
|
| $ | 24 |
|
| $ | 235 |
|
Lease liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Current lease liabilities (1) |
| $ | 8 |
|
| $ | 15 |
|
| $ | 23 |
|
| $ | 8 |
|
| $ | 18 |
|
| $ | 26 |
|
Long-term lease liabilities |
|
| 247 |
|
|
| 4 |
|
|
| 251 |
|
|
| 247 |
|
|
| 5 |
|
|
| 252 |
|
Total lease liabilities |
| $ | 255 |
|
| $ | 19 |
|
| $ | 274 |
|
| $ | 255 |
|
| $ | 23 |
|
| $ | 278 |
|
(1) Current lease liabilities are included in other current liabilities on the consolidated balance sheets.
23
TableDevon’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 Contentsoil and gas. Devon’s right-of-use financing lease assets are related to real estate.
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
The following table presents the changes in Devon’s asset retirement obligations.
|
| Nine Months Ended September 30, |
| |||||||||||||
|
| 2017 |
|
| 2016 |
|
| Three Months Ended March 31, |
| |||||||
|
| (Millions) |
|
| 2022 |
|
| 2021 |
| |||||||
Asset retirement obligations as of beginning of period |
| $ | 1,272 |
|
| $ | 1,414 |
|
| $ | 485 |
| $ | 369 |
| |
Liabilities incurred and assumed through acquisitions |
|
| 30 |
|
|
| 18 |
| ||||||||
Assumed WPX obligations |
| 0 |
| 98 |
| |||||||||||
Liabilities incurred |
| 8 |
| 9 |
| |||||||||||
Liabilities settled and divested |
|
| (53 | ) |
|
| (310 | ) |
| (3 | ) |
| (17 | ) | ||
Revision of estimated obligation |
|
| (184 | ) |
|
| 70 |
|
| (35 | ) |
| 11 |
| ||
Accretion expense on discounted obligation |
|
| 47 |
|
|
| 58 |
|
|
| 7 |
|
|
| 7 |
|
Foreign currency translation adjustment |
|
| 29 |
|
|
| 26 |
| ||||||||
Asset retirement obligations as of end of period |
|
| 1,141 |
|
|
| 1,276 |
|
| 462 |
| 477 |
| |||
Less current portion |
|
| 41 |
|
|
| 46 |
|
|
| 19 |
|
|
| 22 |
|
Asset retirement obligations, long-term |
| $ | 1,100 |
|
| $ | 1,230 |
|
| $ | 443 |
|
| $ | 455 |
|
During the first quarter of 2017, Devon reduced its estimated asset retirement obligations by $184 million primarily due to changes in the assumed inflation rate and retirement dates for its oil and gas assets.
During the first nine months of 2016,2022, Devon reduced its asset retirement obligationobligations by $285$35 million primarily due to extended retirement dates for those obligations that were assumedoil and gas assets, partially offset by purchasers of certain upstream U.S. assets. See Note 2 for additional details.inflation-driven increases to current settlement costs.
|
|
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.
|
|
Common Stock Issued
In January 2016, Devon issued approximately 23 million shares of common stock in conjunction with the STACK asset acquisition discussed in Note 2.
In February 2016, Devon issued 79 million shares of common stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were $1.5 billion.
2419
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Share Repurchases
In November 2021, Devon authorized a share repurchase program of $1.0 billion with a December 31, 2022 expiration date. In February 2022, the Board of Directors authorized an expansion of the share repurchase program to $1.6 billion, and in May 2022, authorized a further expansion to $2.0 billion and extended the expiration date to May 4, 2023. The table below summarizesprovides information regarding purchases of Devon’s common stock under the dividends$2.0 billion share repurchase program (shares in thousands).
|
| Total Number of |
|
| Dollar Value of |
|
| Average Price Paid |
| |||
2021: |
|
|
|
|
|
|
|
|
| |||
Fourth quarter |
|
| 13,983 |
|
| $ | 589 |
|
| $ | 42.15 |
|
2022: |
|
|
|
|
|
|
|
|
| |||
First quarter |
|
| 3,979 |
|
| $ | 230 |
|
| $ | 57.74 |
|
Total plan |
|
| 17,962 |
|
| $ | 819 |
|
| $ | 45.61 |
|
Dividends
Upon completion of the Merger, Devon paid oncontinued 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 |
|
|
|
|
|
In responsecommitment to the depressed commodity price environment, Devon reduced itspay a quarterly dividend at a fixed rate and instituted a variable quarterly dividend, which is dependent on quarterly cash flows, among other factors. Devon raised its fixed quarterly dividend by 45%, to $0.06$0.16 per share, beginning in the first quarter of 2022. The following table summarizes Devon’s fixed and variable dividends for the first quarter of 2022 and 2021, respectively.
| Fixed |
|
| Variable |
|
| Total |
|
| Rate Per Share |
| ||||
2022: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 109 |
|
| $ | 558 |
|
| $ | 667 |
|
| $ | 1.00 |
|
2021: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 76 |
|
| $ | 127 |
|
| $ | 203 |
|
| $ | 0.30 |
|
In May 2022, Devon announced a cash dividend in the amount of $1.27 per share payable in the second quarter of 2016.
|
|
Subsidiary Equity Transactions
EnLink has2022. The dividend consists of a fixed quarterly dividend in the ability to sell common units through its “at the market” equity offering programs. In the third quarter of 2017, EnLink entered into additional equity distribution agreements to sell up to $600 million in common units through its programs. Future common units that EnLink issues will be issued under the new equity distribution agreement. During the first nine months of 2017, EnLink issued and sold 5 million common units through its programs and generated $92 million in net proceeds.
In September 2017, EnLink issued 400,000 preferred units through an underwritten public offering for net proceedsamount of approximately $394 million.
During the first nine months of 2016, EnLink issued$106 million (or $0.16 per share) 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%, excluding the interest held by the General Partner. Devon’s controlling ownership interesta variable quarterly dividend in the General Partner asamount of September 30, 2017 was 64%approximately $732 million (or $1.11 per share). 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.
Distributions to Noncontrolling Interests
EnLinkThe noncontrolling interests’ share of CDM’s net earnings and the General Partner distributed $247 millioncontributions from and $224 milliondistributions to non-Devon unitholders during the first nine monthsnoncontrolling interests are presented as components of 2017equity.
|
|
Devon is party to various legal actions arising in the normal course ofconnection with its business. Matters that are probable of unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in contesting, litigating and settling similar matters. None of the actions are believed by management to 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.
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, paid royalty proceeds in an untimely manner without including required interest, 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. As of March 31, 2022, Devon does not currently believehas accrued approximately $30 million in other current liabilities pertaining to such royalty matters.
20
DEVON ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Environmental and Climate Change Matters
Devon’s business is subject to numerous federal, state, tribal and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties, as well as remediation costs. Although Devon believes that it is subjectin substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its business, there can be no assurance that this will continue in the future.
Beginning 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 material exposureland 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, payment of the costs necessary to clear, re-vegetate and otherwise restore the allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon intends to vigorously defend against these claims.
The State of Delaware and various municipalities and other governmental and private parties in California have filed legal proceedings against numerous oil and gas companies, including Devon, seeking relief to 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 intends to vigorously defend against the proceedings.
Other Indemnifications and Legacy Matters
Pursuant to various sale agreements relating to divested businesses and assets, Devon has indemnified various purchasers against liabilities that they may incur with respect to such royalty matters.the businesses and assets acquired from Devon. Additionally, federal, state and other laws in areas of former operations may require previous operators (including corporate successors of previous operators) to perform or make payments in certain circumstances where the current operator may no longer be able to satisfy the applicable obligation. Such obligations may include plugging and abandoning wells, removing production facilities or performing requirements under surface agreements in existence at the time of disposition.
In November 2020, the Department of the Interior, Bureau of Safety and Environmental Matters
Enforcement, ordered several oil and gas operators, including Devon, is subject to certain environmental, healthperform decommissioning and safety lawsreclamation activities related to two California offshore oil and regulations, including with respectgas production platforms and related facilities. The current operator and owner of the platforms contends that it does not have the financial ability to environmental remediation activities associated with past operations, such asperform these obligations and relinquished the Comprehensive Environmental Response, Compensation, and Liability Act and similar state statutes.related federal lease in October 2020. In response to liabilities associated with these activities, loss accruals primarily consistthe apparent insolvency of estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expectedthe current operator, the government has ordered the former operators and alleged former lease record title owners to decommission the platforms and related facilities. The government contends that an alleged corporate predecessor of Devon owned a partial interest in the subject lease and platforms. Although Devon cannot predict the ultimate outcome of this matter, Devon denies any obligation to decommission the subject platforms, has appealed the order, and believes any decommissioning obligation related to the subject platforms should be material.assumed by others.
21
Other MattersDEVON ENERGY CORPORATION AND SUBSIDIARIES
Devon is involved in other various legal proceedings incidental to its business. However, to Devon’s knowledge, there were no other material pending legal proceedings to which Devon is a party or to which any of its property is subject.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
|
The following table provides carrying value and fair value measurement information for certain of Devon’s financial assets and liabilities. None of the items below are measured using Level 3 inputs. The carrying values of cash, accounts receivable, other current receivables, accounts payable, other current payables, and accrued expenses and lease liabilities included in the accompanying consolidated balance sheets approximated fair value at September 30, 2017March 31, 2022 and December 31, 2016. 2021, as applicable. Therefore, such financial assets and liabilities are not presented in the following table. Additionally, the fair values of oil and gas assets, goodwill and other intangible assets and related impairments are measured as of the impairment date using Level 3 inputs. More information on these items is provided in Note 5 and Note 12, respectively.
|
|
|
|
|
|
|
| Fair Value Measurements Using: |
| |||||||||||
|
| Carrying |
|
| Total Fair |
|
| Level 1 |
|
| Level 2 |
|
| Level 3 |
| |||||
|
| Amount |
|
| Value |
|
| Inputs |
|
| Inputs |
|
| Inputs |
| |||||
March 31, 2022 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash equivalents |
| $ | 2,196 |
|
| $ | 2,196 |
|
| $ | 2,196 |
|
| $ | — |
|
| $ | — |
|
Commodity derivatives |
| $ | 32 |
|
| $ | 32 |
|
| $ | — |
|
| $ | 32 |
|
| $ | — |
|
Commodity derivatives |
| $ | (940 | ) |
| $ | (940 | ) |
| $ | — |
|
| $ | (940 | ) |
| $ | — |
|
Debt |
| $ | (6,471 | ) |
| $ | (7,126 | ) |
| $ | — |
|
| $ | (7,126 | ) |
| $ | — |
|
Contingent earnout payments |
| $ | 115 |
|
| $ | 115 |
|
| $ | — |
|
| $ | — |
|
| $ | 115 |
|
December 31, 2021 assets (liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||
Cash equivalents |
| $ | 1,421 |
|
| $ | 1,421 |
|
| $ | 1,421 |
|
| $ | — |
|
| $ | — |
|
Commodity derivatives |
| $ | 8 |
|
| $ | 8 |
|
| $ | — |
|
| $ | 8 |
|
| $ | — |
|
Commodity derivatives |
| $ | (577 | ) |
| $ | (577 | ) |
| $ | — |
|
| $ | (577 | ) |
| $ | — |
|
Debt |
| $ | (6,482 | ) |
| $ | (7,644 | ) |
| $ | — |
|
| $ | (7,644 | ) |
| $ | — |
|
Contingent earnout payments |
| $ | 184 |
|
| $ | 184 |
|
| $ | — |
|
| $ | — |
|
| $ | 184 |
|
|
|
|
|
|
|
|
|
|
| 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 | ) |
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 equivalentsCommodity 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 ofmaturity when active trading is not available.
Level 3 Fair Value Measurements
Contingent Earnout Payments – Devon has the credit facility balance isright to receive contingent consideration related to the carrying value.
Installment payment – The fair value of the EnLink installment payment wasBarnett and non-core Rockies asset divestitures based on Level 2 inputs from third-party market quotations.
Capital lease obligations – The fair value was calculated using inputs from third-party banks.
|
|
Devon manages its operations through distinct operating segments, which are defined primarily by geographic areas. For financial reporting purposes, Devon aggregates its U.S. operating segments into one reporting segment due to the similar nature of the businesses. However, Devon’s Canadian E&P operating segment is reported as a separate reporting segment primarily due to the significant differences between the U.S. and Canadian regulatory environments. Devon’s U.S. and Canadian segments are both primarily engaged infuture 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.prices. These values were derived using a Monte Carlo valuation model 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 presentedqualify as a separate reporting segment.level 3 fair value measurement. For additional information, see Note 2.
2722
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 periodsperiod ended September 30, 2017March 31, 2022 compared to the three-month and nine-monthprevious periods ended September 30, 2016 and in our financial condition and liquidity since December 31, 2016.2021. For information regarding our critical accounting policies and estimates, see our 20162021 Annual Report on Form 10-K under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Executive Overview
The Merger has helped us become a leading unconventional oil producer in the U.S., with an asset base underpinned by premium acreage in the economic core of 2017 Resultsthe Delaware Basin. This strategic combination accelerated 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 moderating growth, emphasizing capital efficiencies, maintaining and improving operational and corporate synergies, 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:
Key components
|
| 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 | % |
|
|
|
|
|
|
During the first nine monthsquarter of 2017, we generated solid operating results2022 for approximately $230 million, or $57.74 per share.
We remain committed to capital discipline and delivering the objectives that underpin our current plan. Those objectives prioritize value creation through moderated capital investment and production growth, particularly with a view of the steep backwardation in commodity prices, supply chain constraints and the economic uncertainty arising from recent geopolitical events.
Commodity prices strengthened throughout 2021 and oil prices continued to improveincrease in the first quarter of 2022, which has significantly improved 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.
Compared to 2016, commodity prices increased significantly and were the primary driver for improvements in Devon’s operating margins, earnings and cash flow generation. The increase in commodity prices during 2021 was primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic, as well as OPEC+ and other oil and natural gas producers not rapidly increasing production levels. The military conflict between Russia and Ukraine and related economic sanctions imposed on Russia has further exacerbated supply shortages, causing oil prices to increase even more during the first nine monthsquarter of 2017. 2022.
Trends of our quarterly earnings, operating cash flow, EBITDAX and capital expenditures are shown below. “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.
23
Our earnings decreased from the fourth quarter of 2021 to the first quarter of 2022 primarily due to non-cash adjustments related to the value of commodity hedges, lower sold volumes resulting from natural declines and winter weather downtime and lower gas prices. Henry Hub decreased 15% from the fourth quarter of 2021 to the first quarter of 2022. These decreases were partially offset by a 23% increase in WTI from the fourth quarter of 2021 to the first quarter of 2022 which contributed to a 16% increase in our unhedged combined realized prices.
Our net earnings in recent quarters have been significantly impacted by non-cash adjustments to the value of our commodity hedges. Net earnings in the first quarter of 2021, the second quarter of 2021 and the first quarter of 2022 each included a hedge valuation loss, net of tax of $0.2 billion, $0.3 billion and $0.3 billion, respectively. Net earnings in the fourth quarter of 2021 included a hedge valuation gain, net of tax of $0.4 billion. Excluding these amounts, our core earnings have been more stable over recent quarters and continue to trend upward while remaining sensitive to volatile commodity prices.
Like earnings, our operating cash flow is sensitive to volatile commodity prices. Our cash flow and EBITDAX have continued to trend upward primarily due to improved commodity prices and overall market conditions as well as strong operating performance. However, volumes were down slightly in the first quarter of 2022 primarily due to natural declines across the asset portfolio as well as downtime related to winter weather which negatively impacted earnings.
We exited the thirdfirst quarter of 20172022 with $5.6 billion of liquidity, comprised of $2.8$2.6 billion of cash and $2.9$3.0 billion of available credit under our Senior Credit Facility. We currently have $6.5 billion of debt outstanding with no significant debt maturities until 2021. At September 30, 2017, we also hadAugust 2023. We currently have approximately 65%25% and 35% of our remaining 2017 forecastedanticipated 2022 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 and NYMEX last day natural gas indices. Additionally, we have entered into regional basis swaps in an average flooreffort to protect price of $3.10/MMBtu. We are buildingrealizations across our 2018portfolio.
As commodity prices and 2019 hedge positions at similar prices.
We expect to further enhanceour operating performance strengthen and bolster our financial strengthcondition, we have authorized opportunistic repurchases of up to $2.0 billion of our common shares with our announced $1 billion asset divestiture program. The planned divestitures include select portionsan expiration date of May 4, 2023. We repurchased approximately 4.0 million shares in the first quarter of 2022 for approximately $230 million, or $57.74 per share. As of March 31, 2022, we have repurchased approximately 18 million shares for approximately $819 million, or $45.61 per share, since the inception of the Barnett Shale focused primarilyprogram. Additionally, we continue funding our fixed plus variable dividends, which totaled $667 million in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, we have closed non-core divestitures totaling approximately $400 million under this program.the first quarter of 2022. We recently declared a dividend payable in the second quarter of 2022 for $838 million.
2924
We recently unveiled our “2020 Vision,” which is a strategic plan through the endResults of the decadeOperations
The following graphs, discussion and analysis are intended to deliver top-tier returnsprovide an understanding of our results of operations and current financial condition. To facilitate the review, these numbers are being presented before consideration of noncontrolling interests.
Q1 2022 vs. Q4 2021
Our first quarter 2022 net earnings were $995 million, compared to net earnings of $1.5 billion for the fourth quarter of 2021. The graph below shows the change in net earnings from the fourth quarter of 2021 to the first quarter of 2022. The material changes are further discussed by category 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:pages.
|
|
|
|
|
|
|
|
|
|
Production Volumes
30
|
| Q1 2022 |
|
| % of Total |
|
| Q4 2021 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 209 |
|
|
| 73 | % |
|
| 213 |
|
|
| -2 | % |
Anadarko Basin |
|
| 14 |
|
|
| 5 | % |
|
| 14 |
|
|
| 2 | % |
Williston Basin |
|
| 32 |
|
|
| 11 | % |
|
| 36 |
|
|
| -12 | % |
Eagle Ford |
|
| 17 |
|
|
| 6 | % |
|
| 19 |
|
|
| -11 | % |
Powder River Basin |
|
| 12 |
|
|
| 4 | % |
|
| 14 |
|
|
| -9 | % |
Other |
|
| 4 |
|
|
| 1 | % |
|
| 4 |
|
|
| -9 | % |
Total |
|
| 288 |
|
|
| 100 | % |
|
| 300 |
|
|
| -4 | % |
|
| Q1 2022 |
|
| % of Total |
|
| Q4 2021 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 561 |
|
|
| 62 | % |
|
| 577 |
|
|
| -3 | % |
Anadarko Basin |
|
| 210 |
|
|
| 23 | % |
|
| 222 |
|
|
| -5 | % |
Williston Basin |
|
| 54 |
|
|
| 6 | % |
|
| 64 |
|
|
| -15 | % |
Eagle Ford |
|
| 61 |
|
|
| 7 | % |
|
| 60 |
|
|
| 3 | % |
Powder River Basin |
|
| 19 |
|
|
| 2 | % |
|
| 19 |
|
|
| -3 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 1 |
|
|
| -4 | % |
Total |
|
| 906 |
|
|
| 100 | % |
|
| 943 |
|
|
| -4 | % |
|
| Q1 2022 |
|
| % of Total |
|
| Q4 2021 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 92 |
|
|
| 67 | % |
|
| 107 |
|
|
| -14 | % |
Anadarko Basin |
|
| 25 |
|
|
| 19 | % |
|
| 27 |
|
|
| -4 | % |
Williston Basin |
|
| 8 |
|
|
| 6 | % |
|
| 9 |
|
|
| -16 | % |
Eagle Ford |
|
| 9 |
|
|
| 6 | % |
|
| 9 |
|
|
| -1 | % |
Powder River Basin |
|
| 2 |
|
|
| 2 | % |
|
| 2 |
|
|
| -10 | % |
Other |
|
| — |
|
|
| 0 | % |
|
| — |
|
| N/M |
| |
Total |
|
| 136 |
|
|
| 100 | % |
|
| 154 |
|
|
| -12 | % |
25
|
| Q1 2022 |
|
| % of Total |
|
| Q4 2021 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 394 |
|
|
| 69 | % |
|
| 416 |
|
|
| -5 | % |
Anadarko Basin |
|
| 75 |
|
|
| 13 | % |
|
| 78 |
|
|
| -4 | % |
Williston Basin |
|
| 48 |
|
|
| 8 | % |
|
| 55 |
|
|
| -13 | % |
Eagle Ford |
|
| 36 |
|
|
| 6 | % |
|
| 38 |
|
|
| -5 | % |
Powder River Basin |
|
| 18 |
|
|
| 3 | % |
|
| 19 |
|
|
| -7 | % |
Other |
|
| 4 |
|
|
| 1 | % |
|
| 5 |
|
|
| -11 | % |
Total |
|
| 575 |
|
|
| 100 | % |
|
| 611 |
|
|
| -6 | % |
From the fourth quarter of Operations2021 to the first quarter of 2022, the change in volumes contributed to a $220 million decrease in earnings. The decrease in volumes was primarily due to natural declines across the asset portfolio as well as downtime in the Delaware Basin and Williston Basin related to winter weather.
Oil, Gas
Realized Prices
|
| Q1 2022 |
|
| Realization |
| Q4 2021 |
|
| Change |
| |||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 94.45 |
|
|
|
| $ | 76.91 |
|
|
| 23 | % |
Realized price, unhedged |
| $ | 92.94 |
|
| 98% |
| $ | 75.36 |
|
|
| 23 | % |
Cash settlements |
| $ | (11.32 | ) |
|
|
| $ | (13.14 | ) |
|
|
| |
Realized price, with hedges |
| $ | 81.62 |
|
| 86% |
| $ | 62.22 |
|
|
| 31 | % |
|
| Q1 2022 |
|
| Realization |
| Q4 2021 |
|
| Change |
| |||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
| |||
Henry Hub index |
| $ | 4.96 |
|
|
|
| $ | 5.84 |
|
|
| -15 | % |
Realized price, unhedged |
| $ | 3.77 |
|
| 76% |
| $ | 4.68 |
|
|
| -19 | % |
Cash settlements |
| $ | (0.62 | ) |
|
|
| $ | (1.42 | ) |
|
|
| |
Realized price, with hedges |
| $ | 3.15 |
|
| 64% |
| $ | 3.26 |
|
|
| -3 | % |
|
| Q1 2022 |
|
| Realization |
| Q4 2021 |
|
| Change |
| |||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 94.45 |
|
|
|
| $ | 76.91 |
|
|
| 23 | % |
Realized price, unhedged |
| $ | 37.76 |
|
| 40% |
| $ | 35.36 |
|
|
| 7 | % |
Cash settlements |
| $ | — |
|
|
|
| $ | (0.54 | ) |
|
|
| |
Realized price, with hedges |
| $ | 37.76 |
|
| 40% |
| $ | 34.82 |
|
|
| 8 | % |
|
| Q1 2022 |
|
| Q4 2021 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
| |||
Realized price, unhedged |
| $ | 61.40 |
|
| $ | 53.12 |
|
|
| 16 | % |
Cash settlements |
| $ | (6.65 | ) |
| $ | (8.78 | ) |
|
|
| |
Realized price, with hedges |
| $ | 54.75 |
|
| $ | 44.34 |
|
|
| 23 | % |
From the fourth quarter of 2021 to the first quarter of 2022, realized prices contributed to a $410 million increase in earnings. Unhedged realized oil 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 | % |
|
|
|
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 |
|
Commodity salesprices increased in the third quarter and the first nine months of 2017primarily due to price increases for all commodities.higher WTI and Mont Belvieu index prices while realized gas prices decreased slightly due to a lower Henry Hub index price. The increase in oilWTI 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 commodityindex prices was partially offset by a decline inhedge cash settlements related to oil and gas commodities.
We currently have approximately 25% and 35% of our anticipated 2022 oil and gas production volumes. In 2016, we significantly reduced our drilling and completion capital programs in response to depressed commodity prices. Consequently, production from our retained U.S. assets, other than STACK, steadily declined throughout 2016 and into 2017. Our 2016 asset divestiture program also caused our volumes to decline significantly in the third and fourth quarters of 2016. Additionally, Hurricane Harvey negatively impacted our third quarter 2017 production in the Eagle Ford as we temporarily suspended operations.hedged, respectively.
32
26
A summaryHedge Settlements
|
| Q1 2022 |
|
| Q4 2021 |
|
| Change |
| |||
|
| Q |
|
|
|
|
|
|
| |||
Oil |
| $ | (293 | ) |
| $ | (362 | ) |
|
| 19 | % |
Natural gas |
|
| (51 | ) |
|
| (123 | ) |
|
| 59 | % |
NGL |
|
| — |
|
|
| (8 | ) |
| N/M |
| |
Total cash settlements (1) |
| $ | (344 | ) |
| $ | (493 | ) |
|
| 30 | % |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||
|
| 2017 |
|
| 2016 |
|
| 2017 |
|
| 2016 |
| ||||
|
| (Millions) |
| |||||||||||||
Cash settlements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivatives |
| $ | 11 |
|
| $ | 20 |
|
| $ | 29 |
|
| $ | (41 | ) |
Gas derivatives |
|
| 13 |
|
|
| (4 | ) |
|
| 14 |
|
|
| 47 |
|
NGL derivatives |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2 | ) |
Total cash settlements |
|
| 24 |
|
|
| 16 |
|
|
| 43 |
|
|
| 4 |
|
Gains (losses) on fair value changes: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil derivatives |
|
| (157 | ) |
|
| 23 |
|
|
| 72 |
|
|
| (7 | ) |
Gas derivatives |
|
| (7 | ) |
|
| 35 |
|
|
| 101 |
|
|
| (26 | ) |
NGL derivatives |
|
| (4 | ) |
|
| 5 |
|
|
| (2 | ) |
|
| (1 | ) |
Total gains (losses) on fair value changes |
|
| (168 | ) |
|
| 63 |
|
|
| 171 |
|
|
| (34 | ) |
Oil, gas and NGL derivatives |
| $ | (144 | ) |
| $ | 79 |
|
| $ | 214 |
|
| $ | (30 | ) |
|
| Three Months Ended September 30, 2017 |
|
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
|
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
|
| |||||
Realized price without hedges |
| $ | 45.41 |
|
| $ | 31.75 |
|
| $ | 2.45 |
|
| $ | 15.15 |
|
| $ | 25.67 |
|
|
Cash settlements of hedges |
|
| 0.96 |
|
|
| — |
|
|
| 0.12 |
|
|
| (0.03 | ) |
|
| 0.52 |
|
|
Realized price, including cash settlements |
| $ | 46.37 |
|
| $ | 31.75 |
|
| $ | 2.57 |
|
| $ | 15.12 |
|
| $ | 26.19 |
|
|
|
|
|
|
|
| �� |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Three Months Ended September 30, 2016 |
|
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
|
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
|
| |||||
Realized price without hedges |
| $ | 40.12 |
|
| $ | 23.00 |
|
| $ | 2.24 |
|
| $ | 9.80 |
|
| $ | 20.98 |
|
|
Cash settlements of hedges |
|
| 1.56 |
|
|
| — |
|
|
| (0.04 | ) |
|
| 0.10 |
|
|
| 0.32 |
|
|
Realized price, including cash settlements |
| $ | 41.68 |
|
| $ | 23.00 |
|
| $ | 2.20 |
|
| $ | 9.90 |
|
| $ | 21.30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2017 |
|
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
|
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
|
| |||||
Realized price without hedges |
| $ | 45.83 |
|
| $ | 28.49 |
|
| $ | 2.54 |
|
| $ | 14.62 |
|
| $ | 25.41 |
|
|
Cash settlements of hedges |
|
| 0.80 |
|
|
| — |
|
|
| 0.05 |
|
|
| (0.02 | ) |
|
| 0.29 |
|
|
Realized price, including cash settlements |
| $ | 46.63 |
|
| $ | 28.49 |
|
| $ | 2.59 |
|
| $ | 14.60 |
|
| $ | 25.70 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Nine Months Ended September 30, 2016 |
|
| |||||||||||||||||
|
| Oil |
|
| Bitumen |
|
| Gas |
|
| NGLs |
|
| Boe |
|
| |||||
|
| (Per Bbl) |
|
| (Per Bbl) |
|
| (Per Mcf) |
|
| (Per Bbl) |
|
| (Per Boe) |
|
| |||||
Realized price without hedges |
| $ | 34.78 |
|
| $ | 17.77 |
|
| $ | 1.70 |
|
| $ | 8.84 |
|
| $ | 17.37 |
|
|
Cash settlements of hedges |
|
| (0.94 | ) |
|
| — |
|
|
| 0.12 |
|
|
| (0.06 | ) |
|
| 0.02 |
|
|
Realized price, including cash settlements |
| $ | 33.84 |
|
| $ | 17.77 |
|
| $ | 1.82 |
|
| $ | 8.78 |
|
| $ | 17.39 |
|
|
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.
Production Expenses
|
| Q1 2022 |
|
| Q4 2021 |
|
| Change |
| |||
LOE |
| $ | 224 |
|
| $ | 235 |
|
|
| -5 | % |
Gathering, processing & transportation |
|
| 161 |
|
|
| 173 |
|
|
| -7 | % |
Production taxes |
|
| 214 |
|
|
| 197 |
|
|
| 9 | % |
Property taxes |
|
| 19 |
|
|
| — |
|
| N/M |
| |
Total |
| $ | 618 |
|
| $ | 605 |
|
|
| 2 | % |
Per Boe: |
|
|
|
|
|
|
|
|
| |||
LOE |
| $ | 4.33 |
|
| $ | 4.18 |
|
|
| 4 | % |
Gathering, processing & transportation |
| $ | 3.11 |
|
| $ | 3.08 |
|
|
| 1 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
| |||
Production taxes |
|
| 6.7 | % |
|
| 6.6 | % |
|
| 2 | % |
Production expenses remained relatively flat from the fourth quarter of 2021 to the first quarter of 2022. LOE and gathering, processing and transportation expenses decreased primarily due to lower volumes which was offset by an increase in property taxes and production taxes which resulted from higher commodity derivatives. In additionprices.
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 a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash settlements, we alsomargins by asset.
|
| Q1 2022 |
|
| $ per BOE |
|
| Q4 2021 |
|
| $ per BOE |
| ||||
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 1,877 |
|
| $ | 52.99 |
|
| $ | 1,706 |
|
| $ | 44.59 |
|
Anadarko Basin |
|
| 204 |
|
| $ | 30.31 |
|
|
| 212 |
|
| $ | 29.65 |
|
Williston Basin |
|
| 207 |
|
| $ | 47.65 |
|
|
| 209 |
|
| $ | 40.95 |
|
Eagle Ford |
|
| 158 |
|
| $ | 48.92 |
|
|
| 149 |
|
| $ | 42.70 |
|
Powder River Basin |
|
| 86 |
|
| $ | 54.32 |
|
|
| 80 |
|
| $ | 45.61 |
|
Other |
|
| 25 |
|
| $ | 61.96 |
|
|
| 24 |
|
| $ | 55.14 |
|
Total |
| $ | 2,557 |
|
| $ | 49.45 |
|
| $ | 2,380 |
|
| $ | 42.37 |
|
DD&A
|
| Q1 2022 |
|
| Q4 2021 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 8.95 |
|
| $ | 9.79 |
|
|
| -9 | % |
|
|
|
|
|
|
|
|
|
| |||
Oil and gas |
| $ | 463 |
|
| $ | 550 |
|
|
| -16 | % |
Other property and equipment |
|
| 26 |
|
|
| 27 |
|
|
| -3 | % |
Total |
| $ | 489 |
|
| $ | 577 |
|
|
| -15 | % |
DD&A decreased in the first quarter of 2022 primarily due to lower DD&A rates compared to 2021. The decrease in DD&A rates was primarily due to increases to oil, gas and NGL reserve estimates at December 31, 2021, resulting from higher prices.
27
General and Administrative Expense
|
| Q1 2022 |
|
| Q4 2021 |
|
| Change |
| |||
G&A per Boe |
| $ | 1.82 |
|
| $ | 1.70 |
|
|
| 7 | % |
|
|
|
|
|
|
|
|
|
| |||
Labor and benefits |
| $ | 58 |
|
| $ | 58 |
|
|
| 0 | % |
Non-labor |
|
| 36 |
|
|
| 37 |
|
|
| -3 | % |
Total |
| $ | 94 |
|
| $ | 95 |
|
|
| -1 | % |
The G&A per BOE rate increased in the first quarter of 2022 primarily due to lower volumes resulting from natural declines and winter weather downtime.
Other Items
|
| Q1 2022 |
|
| Q4 2021 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | (339 | ) |
| $ | 515 |
|
| $ | (854 | ) |
Marketing and midstream operations |
|
| (4 | ) |
|
| — |
|
|
| (4 | ) |
Exploration expenses |
|
| 2 |
|
|
| 5 |
|
|
| 3 |
|
Asset dispositions |
|
| (1 | ) |
|
| (49 | ) |
|
| (48 | ) |
Net financing costs |
|
| 85 |
|
|
| 86 |
|
|
| 1 |
|
Restructuring and transaction costs |
|
| — |
|
|
| 28 |
|
|
| 28 |
|
Other, net |
|
| (61 | ) |
|
| (2 | ) |
|
| 59 |
|
|
|
|
|
|
|
|
| $ | (815 | ) |
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 commencedAsset dispositions in the fourth quarter of 2016 subsequent2021 includes $49 million related to the salere-valuation 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 costscontingent earnout payments 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 assessments from the local taxing authorities across our key operating areas and as a result of our non-core oil and gas property divestitures during 2016. Property taxes do not always change in direct correlation with the change in oil, gas and NGL sales and are generally determined based on the valuation of the underlying assets.
Depreciation, Depletion and 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 in the third quarter primarily due to lower production and decreased during the first nine months of 2017 largely due to lower DD&A rates, resulting from the oil and gas asset impairments and non-core U.S. divestures in 2016. DD&A from our other assets decreased due to the divestiture of Access Pipeline in the fourth quarter of 2016.
EnLink’s DD&A increased primarily due to acquisitions made during 2016 and gathering system expansions in 2017.
Asset Impairments
During the third quarter and the first nine months of 2016, we recognized asset impairments totaling $319 million and $4.9 billion, respectively.prior divestitures. For further discussion,additional information, see Note 52 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 with the closing of the acquisitions discussed in For discussion on other, net, see Note 26 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
Net Financing Costs
|
| Three Months Ended September 30, |
|
| Nine Months Ended September 30, |
| ||||||||||||||||||
|
| 2017 |
|
| 2016 |
|
| Change |
|
| 2017 |
|
| 2016 |
|
| Change |
| ||||||
|
| (Millions) |
| |||||||||||||||||||||
Devon net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
| $ | 97 |
|
| $ | 120 |
|
|
| - 19 | % |
| $ | 292 |
|
| $ | 376 |
|
|
| - 22 | % |
Early retirement of debt |
|
| — |
|
|
| 84 |
|
| N/M |
|
|
| — |
|
|
| 84 |
|
| N/M |
| ||
Capitalized interest |
|
| (19 | ) |
|
| (16 | ) |
|
| +21 | % |
|
| (53 | ) |
|
| (47 | ) |
|
| +12 | % |
Other |
|
| (1 | ) |
|
| 7 |
|
|
| - 114 | % |
|
| (3 | ) |
|
| 18 |
|
|
| - 117 | % |
Total Devon net financing costs |
|
| 77 |
|
|
| 195 |
|
|
| - 60 | % |
|
| 236 |
|
|
| 431 |
|
|
| - 45 | % |
EnLink net financing costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest based on debt outstanding |
|
| 43 |
|
|
| 37 |
|
|
| +16 | % |
|
| 125 |
|
|
| 105 |
|
|
| +19 | % |
Interest accretion on deferred installment payment |
|
| 7 |
|
|
| 13 |
|
|
| - 46 | % |
|
| 20 |
|
|
| 39 |
|
|
| - 49 | % |
Early retirement of debt |
|
| — |
|
|
| — |
|
| N/M |
|
|
| (9 | ) |
|
| — |
|
| N/M |
| ||
Other |
|
| — |
|
|
| (2 | ) |
|
| N/M |
|
|
| (2 | ) |
|
| (5 | ) |
|
| - 60 | % |
Total EnLink net financing costs |
|
| 50 |
|
|
| 48 |
|
|
| +2 | % |
|
| 134 |
|
|
| 139 |
|
|
| - 3 | % |
Total net financing costs |
| $ | 127 |
|
| $ | 243 |
|
|
| - 48 | % |
| $ | 370 |
|
| $ | 570 |
|
|
| - 35 | % |
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.Income Taxes
EnLink’s interest
|
| Q1 2022 |
|
| Q4 2021 |
| ||
Current expense |
| $ | 103 |
|
| $ | 1 |
|
Deferred expense |
|
| 164 |
|
|
| 149 |
|
Total expense |
| $ | 267 |
|
| $ | 150 |
|
Effective income tax rate |
|
| 21 | % |
|
| 9 | % |
For 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.
Income Taxes
|
| 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 | % |
3628
Q1 2022 vs. Q1 2021
Our first quarter 2022 net earnings were $995 million, compared to expect low current income tax ratesnet earnings of $216 million for the first quarter of 2021. The graph below shows the change in net earnings from the first quarter of 2022 to the first quarter of 2021. The material changes are further discussed by category on the following pages.
Production Volumes
|
| Q1 2022 |
|
| % of Total |
|
| Q1 2021 |
|
| Change |
| ||||
Oil (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 209 |
|
|
| 73 | % |
|
| 172 |
|
|
| 22 | % |
Anadarko Basin |
|
| 14 |
|
|
| 5 | % |
|
| 13 |
|
|
| 11 | % |
Williston Basin |
|
| 32 |
|
|
| 11 | % |
|
| 44 |
|
|
| -29 | % |
Eagle Ford |
|
| 17 |
|
|
| 6 | % |
|
| 16 |
|
|
| 8 | % |
Powder River Basin |
|
| 12 |
|
|
| 4 | % |
|
| 17 |
|
|
| -27 | % |
Other |
|
| 4 |
|
|
| 1 | % |
|
| 6 |
|
|
| -38 | % |
Total |
|
| 288 |
|
|
| 100 | % |
|
| 268 |
|
|
| 8 | % |
|
| Q1 2022 |
|
| % of Total |
|
| Q1 2021 |
|
| Change |
| ||||
Gas (MMcf/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 561 |
|
|
| 62 | % |
|
| 471 |
|
|
| 19 | % |
Anadarko Basin |
|
| 210 |
|
|
| 23 | % |
|
| 200 |
|
|
| 5 | % |
Williston Basin |
|
| 54 |
|
|
| 6 | % |
|
| 49 |
|
|
| 10 | % |
Eagle Ford |
|
| 61 |
|
|
| 7 | % |
|
| 47 |
|
|
| 31 | % |
Powder River Basin |
|
| 19 |
|
|
| 2 | % |
|
| 21 |
|
|
| -10 | % |
Other |
|
| 1 |
|
|
| 0 | % |
|
| 3 |
|
|
| -60 | % |
Total |
|
| 906 |
|
|
| 100 | % |
|
| 791 |
|
|
| 15 | % |
|
| Q1 2022 |
|
| % of Total |
|
| Q1 2021 |
|
| Change |
| ||||
NGLs (MBbls/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 92 |
|
|
| 67 | % |
|
| 60 |
|
|
| 52 | % |
Anadarko Basin |
|
| 25 |
|
|
| 19 | % |
|
| 21 |
|
|
| 19 | % |
Williston Basin |
|
| 8 |
|
|
| 6 | % |
|
| 8 |
|
|
| 0 | % |
Eagle Ford |
|
| 9 |
|
|
| 6 | % |
|
| 6 |
|
|
| 35 | % |
Powder River Basin |
|
| 2 |
|
|
| 2 | % |
|
| 3 |
|
|
| -21 | % |
Other |
|
| — |
|
|
| 0 | % |
|
| 1 |
|
| N/M |
| |
Total |
|
| 136 |
|
|
| 100 | % |
|
| 99 |
|
|
| 37 | % |
|
| Q1 2022 |
|
| % of Total |
|
| Q1 2021 |
|
| Change |
| ||||
Combined (MBoe/d) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
|
| 394 |
|
|
| 69 | % |
|
| 310 |
|
|
| 27 | % |
Anadarko Basin |
|
| 75 |
|
|
| 13 | % |
|
| 68 |
|
|
| 11 | % |
Williston Basin |
|
| 48 |
|
|
| 8 | % |
|
| 61 |
|
|
| -20 | % |
Eagle Ford |
|
| 36 |
|
|
| 6 | % |
|
| 30 |
|
|
| 19 | % |
Powder River Basin |
|
| 18 |
|
|
| 3 | % |
|
| 23 |
|
|
| -23 | % |
Other |
|
| 4 |
|
|
| 1 | % |
|
| 7 |
|
|
| -38 | % |
Total |
|
| 575 |
|
|
| 100 | % |
|
| 499 |
|
|
| 15 | % |
29
From the first quarter of 2021 to the first quarter of 2022, the change in volumes contributed to a $212 million increase in earnings. The increase in volumes was primarily due to continued development in the U.S. segment basedDelaware Basin as well as increased activity in the Anadarko Basin and Eagle Ford. These increases were partially offset by lower volumes in the Williston Basin and Powder River Basin primarily due to natural declines.
Realized Prices
|
| Q1 2022 |
|
| Realization |
| Q1 2021 |
|
| Change |
| |||
Oil (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 94.45 |
|
|
|
| $ | 57.87 |
|
|
| 63 | % |
Realized price, unhedged |
| $ | 92.94 |
|
| 98% |
| $ | 55.28 |
|
|
| 68 | % |
Cash settlements |
| $ | (11.32 | ) |
|
|
| $ | (9.13 | ) |
|
|
| |
Realized price, with hedges |
| $ | 81.62 |
|
| 86% |
| $ | 46.15 |
|
|
| 77 | % |
|
| Q1 2022 |
|
| Realization |
| Q1 2021 |
|
| Change |
| |||
Gas (per Mcf) |
|
|
|
|
|
|
|
|
|
|
| |||
Henry Hub index |
| $ | 4.96 |
|
|
|
| $ | 2.71 |
|
|
| 83 | % |
Realized price, unhedged |
| $ | 3.77 |
|
| 76% |
| $ | 2.84 |
|
|
| 33 | % |
Cash settlements |
| $ | (0.62 | ) |
|
|
| $ | (0.15 | ) |
|
|
| |
Realized price, with hedges |
| $ | 3.15 |
|
| 64% |
| $ | 2.69 |
|
|
| 17 | % |
|
| Q1 2022 |
|
| Realization |
| Q1 2021 |
|
| Change |
| |||
NGLs (per Bbl) |
|
|
|
|
|
|
|
|
|
|
| |||
WTI index |
| $ | 94.45 |
|
|
|
| $ | 57.87 |
|
|
| 63 | % |
Realized price, unhedged |
| $ | 37.76 |
|
| 40% |
| $ | 25.01 |
|
|
| 51 | % |
Cash settlements |
| $ | — |
|
|
|
| $ | (0.20 | ) |
|
|
| |
Realized price, with hedges |
| $ | 37.76 |
|
| 40% |
| $ | 24.81 |
|
|
| 52 | % |
|
| Q1 2022 |
|
| Q1 2021 |
|
| Change |
| |||
Combined (per Boe) |
|
|
|
|
|
|
|
|
| |||
Realized price, unhedged |
| $ | 61.40 |
|
| $ | 39.14 |
|
|
| 57 | % |
Cash settlements |
| $ | (6.65 | ) |
| $ | (5.17 | ) |
|
|
| |
Realized price, with hedges |
| $ | 54.75 |
|
| $ | 33.97 |
|
|
| 61 | % |
From the first quarter of 2021 to the first quarter of 2022, realized prices contributed to a $1.2 billion increase in earnings. Unhedged realized oil, gas and NGL prices increased primarily due to higher WTI, Henry Hub and Mont Belvieu index prices. The increase in index prices was partially offset by hedge cash settlements related to oil and gas commodities.
Hedge Settlements
|
| Q1 2022 |
|
| Q1 2021 |
|
| Change |
| |||
Oil |
| $ | (293 | ) |
| $ | (220 | ) |
|
| -33 | % |
Natural gas |
|
| (51 | ) |
|
| (10 | ) |
|
| -410 | % |
NGL |
|
| — |
|
|
| (2 | ) |
| N/M |
| |
Total cash settlements (1) |
| $ | (344 | ) |
| $ | (232 | ) |
|
| -48 | % |
Cash settlements as presented in the tables above represent realized gains or losses related to the instruments described in Note 73 in “Part I. Financial Information – Item 1. Financial Statements” ofin this report.
30
Production Expenses
|
| Q1 2022 |
|
| Q1 2021 |
|
| Change |
| |||
LOE |
| $ | 224 |
|
| $ | 199 |
|
|
| 13 | % |
Gathering, processing & transportation |
|
| 161 |
|
|
| 129 |
|
|
| 25 | % |
Production taxes |
|
| 214 |
|
|
| 117 |
|
|
| 83 | % |
Property taxes |
|
| 19 |
|
|
| 13 |
|
|
| 46 | % |
Total |
| $ | 618 |
|
| $ | 458 |
|
|
| 35 | % |
Per Boe: |
|
|
|
|
|
|
|
|
| |||
LOE |
| $ | 4.33 |
|
| $ | 4.44 |
|
|
| -3 | % |
Gathering, processing & transportation |
| $ | 3.11 |
|
| $ | 2.87 |
|
|
| 8 | % |
Percent of oil, gas and NGL sales: |
|
|
|
|
|
|
|
|
| |||
Production taxes |
|
| 6.7 | % |
|
| 6.6 | % |
|
| 2 | % |
Production expenses increased primarily due to higher volumes as well as an increase in production taxes resulting from higher commodity prices.
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 a measure defined by GAAP. A reconciliation to the comparable GAAP measures is found in “Non-GAAP Measures” in this Item 2. The changes in production volumes, realized prices and production expenses, shown above, had the following impact on our field-level cash margins by asset.
|
| Q1 2022 |
|
| $ per BOE |
|
| Q1 2021 |
|
| $ per BOE |
| ||||
Field-level cash margin (Non-GAAP) |
|
|
|
|
|
|
|
|
|
|
|
| ||||
Delaware Basin |
| $ | 1,877 |
|
| $ | 52.99 |
|
| $ | 895 |
|
| $ | 32.07 |
|
Anadarko Basin |
|
| 204 |
|
| $ | 30.31 |
|
|
| 85 |
|
| $ | 14.01 |
|
Williston Basin |
|
| 207 |
|
| $ | 47.65 |
|
|
| 161 |
|
| $ | 29.70 |
|
Eagle Ford |
|
| 158 |
|
| $ | 48.92 |
|
|
| 72 |
|
| $ | 26.57 |
|
Powder River Basin |
|
| 86 |
|
| $ | 54.32 |
|
|
| 67 |
|
| $ | 31.99 |
|
Other |
|
| 25 |
|
| $ | 61.96 |
|
|
| 19 |
|
| $ | 28.21 |
|
Total |
| $ | 2,557 |
|
| $ | 49.45 |
|
| $ | 1,299 |
|
| $ | 28.95 |
|
DD&A and Asset Impairments
|
| Q1 2022 |
|
| Q1 2021 |
|
| Change |
| |||
Oil and gas per Boe |
| $ | 8.95 |
|
| $ | 9.78 |
|
|
| -8 | % |
|
|
|
|
|
|
|
|
|
| |||
Oil and gas |
| $ | 463 |
|
| $ | 439 |
|
|
| 5 | % |
Other property and equipment |
|
| 26 |
|
|
| 28 |
|
|
| -6 | % |
Total |
| $ | 489 |
|
| $ | 467 |
|
|
| 5 | % |
DD&A increased primarily due to higher volumes which was partially offset by lower DD&A rates. The decrease in DD&A rates was primarily due to increases to oil, gas and NGL reserve estimates at December 31, 2021, resulting from higher prices.
General and Administrative Expense
|
| Q1 2022 |
|
| Q1 2021 |
|
| Change |
| |||
G&A per Boe |
| $ | 1.82 |
|
| $ | 2.40 |
|
|
| -24 | % |
|
|
|
|
|
|
|
|
|
| |||
Labor and benefits |
| $ | 58 |
|
| $ | 72 |
|
|
| -19 | % |
Non-labor |
|
| 36 |
|
|
| 35 |
|
|
| 3 | % |
Total |
| $ | 94 |
|
| $ | 107 |
|
|
| -12 | % |
General and administrative expenses decreased primarily due to synergies resulting from the Merger.
31
Other Items
|
| Q1 2022 |
|
| Q1 2021 |
|
| Change in earnings |
| |||
Commodity hedge valuation changes (1) |
| $ | (339 | ) |
| $ | (296 | ) |
| $ | (43 | ) |
Marketing and midstream operations |
|
| (4 | ) |
|
| (21 | ) |
|
| 17 |
|
Exploration expenses |
|
| 2 |
|
|
| 3 |
|
|
| 1 |
|
Asset dispositions |
|
| (1 | ) |
|
| (32 | ) |
|
| (31 | ) |
Net financing costs |
|
| 85 |
|
|
| 77 |
|
|
| (8 | ) |
Restructuring and transaction costs |
|
| — |
|
|
| 189 |
|
|
| 189 |
|
Other, net |
|
| (61 | ) |
|
| (29 | ) |
|
| 32 |
|
|
|
|
|
|
|
|
| $ | 157 |
|
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.
Asset dispositions include $35 million in the first quarter of 2021 related to the sale of non-core assets in the Rockies. For additional information, see Note 2 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Net financing costs include a $20 million gain in the first quarter of 2021 related to debt retirements. For additional information, see Note 13 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Restructuring and transaction costs in the first quarter of 2021 reflect workforce reductions in conjunction with the Merger, as well as various transaction costs related to the Merger. For additional information, see Note 5 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
For discussion on other, net, see Note 6 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
Income Taxes
|
| Q1 2022 |
|
| Q1 2021 |
| ||
Current expense (benefit) |
| $ | 103 |
|
| $ | (5 | ) |
Deferred expense (benefit) |
|
| 164 |
|
|
| (243 | ) |
Total expense (benefit) |
| $ | 267 |
|
| $ | (248 | ) |
Effective income tax rate |
|
| 21 | % |
|
| 763 | % |
For discussion on income taxes, see Note 7 in “Part I. Financial Information – Item 1. Financial Statements” in this report.
32
Capital Resources, Uses and Liquidity
Sources and Uses of Cash
The following table presents the major changes in cash and cash equivalents for the ninethree months ended September 30, 2017March 31, 2022 and 2016.2021.
|
| 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 March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Operating cash flow |
| $ | 1,837 |
|
| $ | 592 |
|
WPX acquired cash |
|
| — |
|
|
| 344 |
|
Divestitures of property and equipment |
|
| 26 |
|
|
| 15 |
|
Capital expenditures |
|
| (537 | ) |
|
| (499 | ) |
Equity method investment activity, net |
|
| (14 | ) |
|
| 10 |
|
Debt activity, net |
|
| — |
|
|
| (560 | ) |
Repurchases of common stock |
|
| (211 | ) |
|
| — |
|
Common stock dividends |
|
| (667 | ) |
|
| (203 | ) |
Noncontrolling interest activity, net |
|
| (8 | ) |
|
| (28 | ) |
Other |
|
| (72 | ) |
|
| (30 | ) |
Net change in cash, cash equivalents and restricted cash |
| $ | 354 |
|
| $ | (359 | ) |
Cash, cash equivalents and restricted cash at end of period |
| $ | 2,625 |
|
| $ | 1,878 |
|
Operating Cash Flow and WPX Acquired Cash
NetAs presented in the table above, net cash provided by operating activities increased 96%continued to be a significant source of capital and liquidity. Operating cash flow more than tripled during the three months ended March 31, 2022 compared to the three months ended March 31, 2021. The increase was primarily due to significantly higherincreased commodity prices as well as higher volumes for the first three months of 2022 compared to the first nine months of 2016.2021.
Our consolidated operating cash flow funded 100% of our capital expenditures during the first nine months of 2017. In 2016, leveraging our liquidity, we also used cash balances and proceeds from our common stock offering and non-core asset divestitures to fund our acquisitions and capital expenditures.
Divestitures of Property and Equipment
During the first ninethree months of 2017, as part of our announced divestiture program,2022 and 2021, we received contingent consideration related to asset divestitures and 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.respectfully. For further discussion,additional information, please 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 stock to the public, inclusive of 10 million shares sold as part of the underwriters’ option. Net proceeds from the offering were approximately $1.5 billion.
Proceeds from Sale of 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 amounts in the table below reflect cash payments for 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 |
|
|
| Three Months Ended March 31, |
| |||||
|
| 2022 |
|
| 2021 |
| ||
Delaware Basin |
| $ | 395 |
|
| $ | 397 |
|
Anadarko Basin |
|
| 10 |
|
|
| 9 |
|
Williston Basin |
|
| 23 |
|
|
| 28 |
|
Eagle Ford |
|
| 26 |
|
|
| 14 |
|
Powder River Basin |
|
| 33 |
|
|
| 33 |
|
Other |
|
| 3 |
|
|
| — |
|
Total oil and gas |
|
| 490 |
|
|
| 481 |
|
Midstream |
|
| 29 |
|
|
| 5 |
|
Other |
|
| 18 |
|
|
| 13 |
|
Total capital expenditures |
| $ | 537 |
|
| $ | 499 |
|
Capital expenditures consist primarily of amounts related to our oil and gas exploration and development operations, midstream operations and 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 constructionmoderating our production growth and expansion of oil and gas gathering facilities and pipelines. Midstreammaximizing our returns. As such, our 2022 capital expenditures are largely impacted by oil and gas development activities.represent approximately 30% of our operating cash flow.
Acquisition capital for33
Equity Method Investments
During the first ninethree months of 2016 primarily consisted2022 and 2021, Devon received distributions from our equity method investments of Devon’s acquisition$8 million and $10 million, respectively. Devon contributed $22 million to our equity method investments during the first three months of assets2022.
Debt Activity
Subsequent to the Merger closing, we redeemed $533 million of senior notes in the STACK playfirst quarter of 2021. We also paid $27 million of cash retirement costs related to these redemptions.
Shareholder Distributions and Stock Activity
We repurchased approximately 4.0 million shares of common stock for approximately $1.5 billion and EnLink’s acquisition$230 million in the first quarter of Anadarko Basin gathering and processing midstream assets for $1.4 billion. Approximately $850 million and $800 million, respectively, was paid in cash at2022 under the closings with the remainder funded with equity consideration and debt.share repurchase program authorized by our Board of Directors. For additional information, see Note 216 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 first nine monthsquarter 2022 and 2021. In February 2022, our Board of 2017 and 2016.Directors increased our fixed dividend rate by 45% to $0.16 per share. In addition to the secondfixed quarterly dividend, we paid a variable dividend of $0.84 per share in the first quarter of 2016, we decreased our quarterly cash dividend rate to $0.062022 and $0.19 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 duringshare in the first nine monthsquarter of 2017 and 2016, respectively.2021.
EnLink and General Partner Distributions
| Fixed |
|
| Variable |
|
| Total |
|
| Rate Per Share |
| ||||
2022: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 109 |
|
| $ | 558 |
|
| $ | 667 |
|
| $ | 1.00 |
|
2021: |
|
|
|
|
|
|
|
|
|
|
| ||||
First quarter | $ | 76 |
|
| $ | 127 |
|
| $ | 203 |
|
| $ | 0.30 |
|
Noncontrolling Interest Activity, net
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 ninethree months of 2017, EnLink issued2022 and sold 52021, we distributed $8 million common units through its “atand $4 million, respectively, to our noncontrolling interests in CDM. In the market” programs and generated $92first quarter of 2021, we paid $24 million in net proceeds. In September 2017, EnLink issued preferred units in an underwritten public offering generating net proceedsto purchase the noncontrolling interest portion of approximately $394 million.
In January 2016, as part of its acquisition of Anadarko Basin gathering and processing midstream assets, EnLink issued 50 million preferred units in a private placement generating cash proceeds of approximately $725 million. General Partner common units were also issued as considerationpartnership that WPX had formed to acquire minerals in the transaction. Additionally, during the first nine monthsDelaware Basin.
Liquidity
The business of 2016, EnLink issuedexploring for, developing and sold 7 million common units for net proceedsproducing 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 $110 million through its “at the market” programs.assets.
Liquidity
OurHistorically, our primary sources of capital funding and liquidity arehave been our operating cash flow, cash on hand and asset divestiture proceeds and cash on hand.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. Available sources of capital and liquidityIf needed, we can also include, among other things,issue debt and equity securities, that can be issued pursuant toincluding through transactions under 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.SEC. We estimate the combination of theseour sources of capital will continue to be adequate to fund our planned capital expenditures, future debt repayments and other contractual commitmentsrequirements as discussed in this section.section as well as accelerate our cash-return business model.
Operating Cash Flow
Key inputs into determining our planned capital investment are the amount 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 first quarter of 2022, we held approximately $2.6 billion of cash, inclusive of approximately $150 million of cash restricted primarily for retained obligations related to divested assets. Our operating cash flow isforecasts are sensitive to many variables theand include a measure of uncertainty as actual results 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 highly 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.
3934
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%The key terms to our oil, gas and NGL derivative financial instruments as of our productionMarch 31, 2022 are presented in a manner that systematically places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that take advantage of favorable market conditions. For additional information on our derivative positions in place at September 30, 2017, see Note 3 in “Part I. Financial Information – Item 1. Financial Statements” inof this report.
DivestituresFurther, when considering the current commodity price environment and our current hedge position, we expect to achieve our capital investment priorities. Additionally, we remain committed to capital discipline and focused on delivering the objectives that underpin our capital plan for 2022. We will continue to prioritize economic value over growing volumes, which is driven partially by current commodity price backwardation, supply chain constraints and economic uncertainty arising from recent geopolitical events.
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 Propertyrising commodity prices. Furthermore, the COVID-19 pandemic has contributed to disruption and Equipmentvolatility in our supply chain, which has resulted, and may continue to result in labor shortages, increased costs and delays for pipe and other materials needed for our operations.
In May 2017,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 owners for their proportionate share of expenditures made on projects we announcedoperate and counterparties to our derivative financial contracts. We utilize a programvariety of mechanisms to divestlimit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, requiring letters of credit, prepayments or cash collateral postings.
Credit Availability
As of March 31, 2022, we had approximately $1$3.0 billion of upstream assets. These non-core assets identified for monetization include select portions of the Barnett Shale focused primarily in and around Johnson County and other properties located principally within Devon’s U.S. resource base. Through September 30, 2017, Devon completed divestiture transactions totaling approximately $400 million, before purchase price adjustments. The most significant asset remaining in this program is select Barnett Shale leasehold. Data rooms for the Barnett properties opened in September 2017 and initial bids are expected during the fourth quarter of 2017.
Capital Expenditures
Excluding EnLink,available borrowing capacity under our 2017 capital expenditures are expected to range from $2.4 billion to $2.5 billion, including $2.0 billion to $2.1 billion for our exploration and development capital program. Our capital expenditures excluding EnLink were $1.7 billion in the first nine months of 2017 and are forecasted to range from $0.7 billion to $0.8 billion in the fourth quarter of 2017.
Credit Availability
We have a $3.0 billion Senior Credit Facility. As of September 30, 2017, we had approximately $2.9 billion available under this facility, net of $59 million in outstanding letters of credit, and were in compliance with the facility’s financial covenant. This credit facility supports our $3.0 billion of short-term credit under our commercial paper program. At September 30, 2017,March 31, 2022, there were no borrowings under our commercial paper program.program, and we were in compliance with the Senior Credit Facility’s financial covenant.
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, there were $9 million in outstanding letters of credit and no outstanding borrowings under the $1.5 billion credit facility and $74 million in outstanding borrowings under the $250 million credit facility. All of EnLink’s and the General Partner’s debt is non-recourse to Devon.
In January 2017, EnLink paid the first $250 million installment payment related to the 2016 Anadarko Basin gathering and processing midstream assets acquisition. The remaining $250 million installment payment is payable by January 2018.
Debt Ratings
We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and near-term and long-term production growth opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB with a stable outlook. In March 2017,Our credit rating from Fitch Ratings affirmed ouris BBB+ with a stable outlook. Our credit rating and revised our outlook to stable from negative. In April 2017, Moody’s Investor Service upgraded our credit rating from Ba2 to Ba1is Baa3 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” in any of our or EnLink’s contractual debt obligations that would accelerate scheduled maturities should aour debt rating fall below a specified level. However, these downgradesa downgrade could adversely impact our and EnLink’s interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.
Fixed Plus Variable Dividend
40We are committed to a “fixed plus variable” dividend strategy. Our Board of Directors will consider a number of factors when setting the quarterly dividend, if any, including a general target of paying out approximately 10% of operating cash flow through the fixed dividend. In February 2022, our Board of Directors increased our quarterly fixed dividend rate by 45% to $0.16 per share. In addition to the fixed quarterly dividend, we may pay a variable dividend up to 50% of our excess free cash flow, which is a non-GAAP measure. Each quarter’s excess free cash flow is computed as operating cash flow (a GAAP measure) before balance sheet changes, less capital expenditures and the fixed dividend. The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of our Board of Directors and will depend on our financial results, cash requirements, future prospects and other factors deemed relevant by the Board.
In May 2022, Devon announced a cash dividend in the amount of $1.27 per share payable in the second quarter of 2022. The dividend consists of a fixed quarterly dividend in the amount of approximately $106 million (or $0.16 per share) and a variable quarterly dividend in the amount of approximately $732 million (or $1.11 per share).
35
Share Repurchases
In May 2022, our Board of Directors increased our share repurchase program by $0.4 billion to a total authorized amount of $2.0 billion, and extended the expiration date to May 4, 2023. Through April 29, 2022, we had executed $891 million of the authorized program.
Capital Expenditures
Our 2022 exploration and development budget for the remainder of 2022 is expected to range from approximately $1.4 billion to $1.7 billion.
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, we continued to have a 100% valuation allowance against the U.S. deferred tax assets that largely resulted from prior year cumulative financial losses primarily due to full cost impairments. Further, we continue to record a partial valuation allowance against certain Canadian deferred tax assets.
The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as facts and circumstances change. Material changes to our income tax accruals may occurFurther, in the future basedevent we were to undergo an “ownership change” (as defined in Section 382 of the Internal Revenue Code of 1986, as amended), our ability to use net operating losses and tax credits generated prior to the ownership change may be limited. Generally, an “ownership change” occurs if one or more shareholders, each of whom owns five percent or more in value of a corporation’s stock, increase their aggregate percentage ownership by more than 50 percent over the lowest percentage of stock owned by those shareholders at any time during the preceding three-year period. Based on currently available information, we do not believe an ownership change has occurred during 2022 for Devon, but the progress of ongoing audits, changes in legislation or resolution of other pending matters.Merger did cause an ownership change for WPX and increased the likelihood Devon could experience an ownership change over the next two years.
For additional information regarding our critical accounting policies and estimates, see our 2021 Annual Report on Form 10-K.
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 2017 Results”“Executive Overview” 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 noncashnon-cash and other items that are typically excluded by securities analysts in their published estimates of our financial results. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for the third quarter and first nine months of 2017 relate to asset dispositions, non-cash asset impairments (including non-cash unproved asset impairments), deferred tax asset valuation allowance, fair value changes in derivatives andderivative financial instrument fair valuesinstruments and foreign currency, gains and losses on asset sales, noncash asset impairments, gainscosts associated with early retirement of debt and deferred tax asset valuation allowance. Amounts excluded for the third quarter and first nine months of 2016 relate to changes in derivatives and financial instrument fair values and foreign currency, noncash asset impairments (including an impairment of goodwill), restructuring and transaction costs gains on asset sales, costs associated with the early retirement of debt and deferred tax asset valuation allowance. workforce reductions described further in Note 5.
We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our performance between periods and to the performance of our peers.
41
36
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 | ) |
42
| Three Months Ended March 31, |
| |||||||||||||
| Before Tax |
|
| After Tax |
|
| After Noncontrolling Interests |
|
| Per Diluted Share |
| ||||
2022 |
|
|
|
|
|
|
|
|
|
|
| ||||
Earnings attributable to Devon (GAAP) | $ | 1,262 |
|
| $ | 995 |
|
| $ | 989 |
|
| $ | 1.48 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
| ||||
Asset dispositions |
| (1 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
Deferred tax asset valuation allowance |
| — |
|
|
| 6 |
|
|
| 6 |
|
|
| 0.01 |
|
Fair value changes in financial instruments |
| 338 |
|
|
| 260 |
|
|
| 260 |
|
|
| 0.39 |
|
Core earnings attributable to Devon (Non-GAAP) | $ | 1,599 |
|
| $ | 1,261 |
|
| $ | 1,255 |
|
| $ | 1.88 |
|
2021 |
|
|
|
|
|
|
|
|
|
|
| ||||
Earnings (loss) attributable to Devon (GAAP) | $ | (32 | ) |
| $ | 216 |
|
| $ | 213 |
|
| $ | 0.32 |
|
Adjustments: |
|
|
|
|
|
|
|
|
|
|
| ||||
Asset dispositions |
| (32 | ) |
|
| (24 | ) |
|
| (24 | ) |
|
| (0.04 | ) |
Asset and exploration impairments |
| 1 |
|
|
| — |
|
|
| — |
|
|
| — |
|
Deferred tax asset valuation allowance |
| — |
|
|
| (263 | ) |
|
| (263 | ) |
|
| (0.40 | ) |
Fair value changes in financial instruments and foreign currency |
| 294 |
|
|
| 225 |
|
|
| 225 |
|
|
| 0.34 |
|
Restructuring and transaction costs |
| 189 |
|
|
| 162 |
|
|
| 162 |
|
|
| 0.25 |
|
Early retirement of debt |
| (20 | ) |
|
| (15 | ) |
|
| (15 | ) |
|
| (0.02 | ) |
Core earnings attributable to Devon (Non-GAAP) | $ | 400 |
|
| $ | 301 |
|
| $ | 298 |
|
| $ | 0.45 |
|
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 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 operations.
37
Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash Margin.
| Three Months Ended March 31, |
| |||||
| 2022 |
|
| 2021 |
| ||
Net earnings (GAAP) | $ | 995 |
|
| $ | 216 |
|
Financing costs, net |
| 85 |
|
|
| 77 |
|
Income tax expense (benefit) |
| 267 |
|
|
| (248 | ) |
Exploration expenses |
| 2 |
|
|
| 3 |
|
Depreciation, depletion and amortization |
| 489 |
|
|
| 467 |
|
Asset dispositions |
| (1 | ) |
|
| (32 | ) |
Share-based compensation |
| 20 |
|
|
| 20 |
|
Derivative and financial instrument non-cash valuation changes |
| 339 |
|
|
| 296 |
|
Restructuring and transaction costs |
| — |
|
|
| 189 |
|
Accretion on discounted liabilities and other |
| (61 | ) |
|
| (29 | ) |
EBITDAX (Non-GAAP) |
| 2,135 |
|
|
| 959 |
|
Marketing and midstream revenues and expenses, net |
| 4 |
|
|
| 21 |
|
Commodity derivative cash settlements |
| 344 |
|
|
| 232 |
|
General and administrative expenses, cash-based |
| 74 |
|
|
| 87 |
|
Field-level cash margin (Non-GAAP) | $ | 2,557 |
|
| $ | 1,299 |
|
38
Item 3. Quantitative and QualitativeQualitative Disclosures About Market Risk
Commodity Price Risk
As of September 30, 2017,March 31, 2022, we have commodity derivatives that pertain to a portion of our estimated production for the last threenine months of 2017,2022, as well as 2018for 2023 and 2019.2024. The key terms to our open oil, gas and NGL derivative financial instruments are presented in Note 3 in “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,March 31, 2022, a 10% change in the forward curves associated with our commodity derivative instruments would have changed our net asset positions by approximately $170$225 million.
Interest Rate Risk
As of September 30, 2017,March 31, 2022, we had total debt of $10.4$6.5 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%5.8%.
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 our September 30, 2017 balance sheet.We had no material foreign currency risk at March 31, 2022.
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, 2017March 31, 2022 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.
4339
PART II. Other Information
We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the date of this report and subject to the environmental matters noted in Part I, Item 3. Legal Proceedings of our 2021 Annual Report on Form 10-K, 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 20162021 Annual Report on Form 10-K and other SEC filings for additional information regarding certain environmental matters involving the Company.information.
There have been no material changes to the information included in Item 1A. “Risk Factors” in our 20162021 Annual Report on Form 10-K.10-K.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information regarding purchases of our common stock that were made by us during the thirdfirst quarter of 2017.2022 (shares in thousands).
Period |
| Total Number of Shares Purchased (1) |
|
| Average Price Paid per Share |
| ||
July 1 - July 31 |
|
| 48,112 |
|
| $ | 32.08 |
|
August 1 - August 31 |
|
| 16,504 |
|
| $ | 31.69 |
|
September 1 - September 30 |
|
| 1,108 |
|
| $ | 31.81 |
|
Total |
|
| 65,724 |
|
| $ | 31.97 |
|
Period |
| Total Number of |
|
| Average Price |
|
| 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) |
| ||||
January 1 - January 31 |
|
| 10 |
|
| $ | 48.58 |
|
|
| — |
|
| $ | 411 |
|
February 1 - February 28 |
|
| 1,872 |
|
| $ | 52.34 |
|
|
| 888 |
|
| $ | 964 |
|
March 1 - March 31 |
|
| 3,494 |
|
| $ | 59.25 |
|
|
| 3,091 |
|
| $ | 781 |
|
Total |
|
| 5,376 |
|
| $ | 56.82 |
|
|
| 3,979 |
|
|
|
|
|
|
Under(1)
Similarly, eligible Canadian employees may purchase shares of our common stock through an investment“Part I. Financial Information – Item 1. Financial Statements” 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.
4440
Exhibit Number |
| Description | |
| 10.1* | ||
10.2* | |||
10.3* | Employment Agreement, dated March 2, 2022, by and between Devon Energy Corporation and Ms. Tana K. Cashion (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed March 7, 2022; File No. 001-32318). | ||
31.1 | |||
31.2 | |||
32.1 | |||
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. |
4541
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| DEVON ENERGY CORPORATION | ||
Date: |
|
| /s/ Jeremy D. Humphers | |
|
| Jeremy D. Humphers | ||
|
| Senior Vice President and Chief Accounting Officer |
42
46